e10vk

Percent of Total

Description

Revenues in 2008^{(1) (2)}

Reservation

Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline system and storage facilities. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts.

Usage and Other

Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) that pay usage charges based on the volume of gas actually transported, stored, injected or withdrawn. We also earn revenue from other miscellaneous sources.

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to .

Commission File Number 1-2745

Southern Natural Gas Company

(Exact Name of Registrant as Specified in Its Charter)


Delaware		63-0196650
(State or Other Jurisdiction of		(I.R.S. Employer
Incorporation or Organization)		Identification No.)

El Paso Building
1001 Louisiana Street
Houston, Texas		77002
(Address of Principal Executive Offices)		(Zip Code)

Telephone Number: (713) 420-2600

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

State the aggregate market value of the voting equity held by non-affiliates of the registrant: None

Documents Incorporated by Reference: None

PART I

ITEM 1. BUSINESS

Overview and Strategy

We are a Delaware general partnership, originally formed in 1935 as a corporation. We are owned 75 percent indirectly through a wholly owned subsidiary of El Paso Corporation (El Paso) and 25 percent by EPPP SNG GP Holdings, L.L.C., a subsidiary of El Paso Pipeline Partners, L.P., El Paso’s master limited partnership (MLP). El Paso’s MLP was formed in November 2007 at which time El Paso contributed 10 percent of its interest in us to the MLP. In September 2008, El Paso’s MLP acquired an additional 15 percent ownership interest in us from El Paso.

In November 2007, in conjunction with the formation of El Paso’s MLP, we distributed our 50 percent interest in Citrus Corp. (Citrus) and our wholly owned subsidiaries, Southern LNG, Inc. (SLNG) and Elba Express Company, LLC (Elba Express), to El Paso. Citrus owns the Florida Gas Transmission Company, LLC (FGT) pipeline system and SLNG owns the Elba Island LNG facility. SLNG and Elba Express have been reflected as discontinued operations in our financial statements for periods prior to their distribution. For a further discussion of these discontinued operations, see Part II, Item 8, Financial Statements and Supplementary Data, Note 2. In addition, effective November 1, 2007, we converted our legal structure into a general partnership, and are no longer subject to income taxes. Accordingly, we settled our then existing current and deferred tax balances through El Paso’s cash management program pursuant to our tax sharing agreement with El Paso.

Our pipeline system and storage facilities operate under tariffs approved by the Federal Energy Regulatory Commission (FERC) that establish rates, cost recovery mechanisms and other terms and conditions of services to our customers. The fees or rates established under our tariff are a function of our costs of providing services to our customers, including a reasonable return on our invested capital.

Our strategy is to enhance the value of our transportation and storage business by:

	•		Successfully executing on our backlog of committed expansion projects;

	•		Developing new growth projects in our market and supply areas;

	•		Focusing on efficiency and synergies across our system;

	•		Ensuring the safety of our pipeline system and assets;

	•		Successfully recontracting or contracting expiring or available capacity; and

	•		Providing outstanding customer service.

Pipeline System. Our pipeline system consists of approximately 7,600 miles of pipeline with a design capacity of 3,700 MMcf/d. During 2008, 2007 and 2006, average throughput was 2,339 BBtu/d, 2,345 BBtu/d and 2,167 BBtu/d. This system extends from supply basins in Texas, Louisiana, Mississippi, Alabama and the Gulf of Mexico to market areas in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee, including the metropolitan areas of Atlanta and Birmingham. We are the principal natural gas transporter to the southeastern markets in Alabama, Georgia and South Carolina. Our system is also connected to the Elba Island LNG terminal near Savannah, Georgia. This terminal has a peak send-out capacity of approximately 1.2 Bcf/d.

FERC Approved Pipeline Expansion Project. As of December 31, 2008, we had the following FERC-approved expansion project on our system. For a further discussion of our other expansion projects, see Item 7, Management’s Discussion and Analysis of Financial Conditions and Results of Operations.


				Anticipated
	Capacity			Completion or
Project	(MMcf/d)		Description	In-Service Date
Cypress Phase III		161	To add 20,700 horsepower of additional compression on our pipeline facilities extending southward from El Paso’s Elba Island facility	First half of 2011

Storage Facilities. Along our pipeline system, we own and operate 100 percent of the Muldon storage facility in Monroe County, Mississippi and own a 50 percent interest in and operate the Bear Creek Storage Company (Bear Creek) in Bienville Parish, Louisiana. Bear Creek provides storage services pursuant to firm contracts to us and Tennessee Gas Pipeline Company (TGP), a subsidiary of El Paso, which owns the remaining 50 percent interest. Our interest in Bear Creek and the Muldon storage facilities have a combined working natural gas storage capacity of 60 Bcf and peak withdrawal capacity of 1.2 Bcf/d. We provide storage services to our customers utilizing the Bear Creek and the Muldon storage facilities at our FERC tariff rate.

Markets and Competition

Our customers consist of natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines and natural gas marketing and trading companies. We provide transportation and storage services in both our natural gas supply and market areas. Our pipeline system connects with multiple pipelines that provide our customers with access to diverse sources of supply and various natural gas markets.

The southeastern market served by our pipeline is the fastest growing natural gas demand region in the United States. Demand for deliveries from our pipeline is characterized by two peak delivery periods, the winter heating season and the summer cooling season.

Imported LNG has been a growing supply sector of the natural gas market. LNG terminals and other regasification facilities can serve as alternate sources of supply for pipelines, enhancing their delivery capabilities and operational flexibility and complementing traditional supply transported into market areas. However, these LNG delivery systems also may compete with us for transportation of gas into market areas we serve.

Electric power generation has been a growing demand sector of the natural gas market. The growth of the natural gas fired electric power benefits the natural gas industry by creating more demand for natural gas. This potential benefit is offset, in varying degrees, by increased generation efficiency, the more effective use of surplus electric capacity and the use and availability of other fuel sources for power generation. In addition, in several regions of the country, new additions in electric generating capacity have exceeded load growth and electric transmission capabilities out of those regions. These developments may inhibit owners of new power generation facilities from signing firm natural gas transportation contracts with natural gas pipelines.

We expect growth of the natural gas market will be adversely affected by the current economic recession in the U.S. and global economies. The decline in economic activity will reduce industrial demand for natural gas and electricity, which will cause lower natural gas demand both directly in end-use markets and indirectly through lower power generation demand for natural gas. The demand for natural gas and electricity in the residential and commercial segments of the market will likely be less affected by the economy. The lower demand and the credit restrictions on investments in the current environment may also slow development of supply projects. While our pipeline could experience some level of reduced throughput and revenues, or slower development of expansion projects as a result of these factors, we generate a significant (greater than 80 percent) portion of our revenues through fixed monthly reservation or demand charges on long-term contracts at rates stipulated under our tariff.

Our existing transportation and storage contracts mature at various times and in varying amounts of throughput capacity. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated

contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs, although at times, we enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive.

We face competition in a number of our key markets. We compete with other interstate and intrastate pipelines for deliveries to multiple-connection customers who can take deliveries at alternative points. Natural gas delivered on our system competes with alternative energy sources used to generate electricity, such as hydroelectric power, coal and fuel oil. Our four largest customers are able to obtain a significant portion of their natural gas requirements through transportation from other pipelines. Also, we compete with several pipelines for the transportation business of our other customers. In addition, we compete with pipelines and gathering systems for connection to new supply sources.

Our most direct competitor is Transco, which owns an approximately 10,500-mile pipeline extending from Texas to New York. It has firm transportation contracts with some of our largest customers, including Atlanta Gas Light Company, Alabama Gas Corporation, Southern Company Services, and SCANA Corporation.

The following table details our customer and contract information related to our pipeline system as of December 31, 2008. Firm customers reserve capacity on our pipeline system and storage facilities and are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. Interruptible customers are customers without reserved capacity that pay usage charges based on the volume of gas they transport, store, inject or withdraw.


Customer Information		Contract Information
Approximately 270 firm and interruptible customers		Approximately 190 firm transportation contracts. Weighted average remaining contract term of approximately five years.

Major Customers:
Atlanta Gas Light Company⁽¹⁾
(30 BBtu/d)		Expires in 2009.
(152 BBtu/d)		Expires in 2010.
(282 BBtu/d)		Expires in 2011.
(545 BBtu/d)		Expires in 2012-2015.

Southern Company Services
(28 BBtu/d)		Expires in 2010.
(390 BBtu/d)		Expires in 2017-2018.

Alabama Gas Corporation
(39 BBtu/d)		Expires in 2010.
(323 BBtu/d)		Expires in 2011.
(31 BBtu/d)		Expires in 2013.

SCANA Corporation
(8 BBtu/d)		Expires in 2009.
(161 BBtu/d)		Expires in 2010.
(146 BBtu/d)		Expires in 2017-2019.


⁽¹⁾		Atlanta Gas Light Company is currently releasing a significant portion of its firm capacity to a subsidiary of SCANA Corporation under terms allowed by our tariff.

Regulatory Environment

Our interstate natural gas transmission system and storage operations are regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We operate under tariffs approved by the FERC that establish rates, cost recovery mechanisms and other terms and conditions of services to our customers. Generally, the FERC’s authority extends to:

	•		certification and construction of new facilities;

	•		extension or abandonment of services and facilities;

	•		maintenance of accounts and records;

	•		relationships between pipelines and certain affiliates;

	•		terms and conditions of service;

	•		depreciation and amortization policies;

	•		acquisition and disposition of facilities; and

	•		initiation and discontinuation of services.

Our interstate pipeline system is also subject to federal, state and local safety and environmental statutes and regulations of the U.S. Department of Transportation and the U.S. Department of the Interior. We have ongoing inspection programs designed to keep our facilities in compliance with pipeline safety and environmental requirements and we believe that our system is in material compliance with the applicable regulations.

Environmental

A description of our environmental activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 7, and is incorporated herein by reference.

Employees

We do not have employees. Following our reorganization, our former employees continue to provide services to us through an affiliated service company owned by our general partner, El Paso. We are managed and operated by officers of El Paso, our general partner. We have an omnibus agreement with El Paso and its affiliates under which we reimburse El Paso for the provision of various general and administrative services for our benefit and for direct expenses incurred by El Paso on our behalf.

ITEM 1A. RISK FACTORS

CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from actual results, and differences between assumed facts and actual results can be material, depending upon the circumstances. Where, based on assumptions, we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur, be achieved or accomplished. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the Securities and Exchange Commission (SEC) from time to time and the following important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by us or on our behalf.

Risks Related to Our Business

Our success depends on factors beyond our control.

The financial results of our transportation and storage operations are impacted by the volumes of natural gas we transport or store and the prices we are able to charge for doing so. The volume of natural gas we are able to transport and store depends on the actions of third parties, including our customers, and is beyond our control. Further, the following factors, most of which are also beyond our control, may unfavorably impact our ability to maintain or increase current throughput, or to remarket unsubscribed capacity on our pipeline system:

	•		service area competition;

	•		price competition;

	•		expiration or turn back of significant contracts;

	•		changes in regulation and actions of regulatory bodies;

	•		weather conditions that impact natural gas throughput and storage levels;

	•		weather fluctuations or warming or cooling trends that may impact demand in the markets in which we do business, including trends potentially attributed to climate change;

	•		drilling activity and decreased availability of conventional gas supply sources and the availability and timing of other gas supply sources, such as LNG;

	•		continued development of additional sources of gas supply that can be accessed;

	•		decreased natural gas demand due to various factors, including economic recession (as further discussed below) and increases in prices;

	•		legislative, regulatory or judicial actions, such as mandatory greenhouse gas regulations and/or legislation, that could result in (i) changes in the demand for natural gas and oil, (ii) changes in the availability of or demand for alternative energy sources such as hydroelectric and nuclear power, wind and solar and/or (iii) changes in the demand for less carbon intensive energy sources;

	•		availability and cost to fund ongoing maintenance and growth projects, especially in periods of prolonged economic decline;

	•		opposition to energy infrastructure development, especially in environmentally sensitive areas;

	•		adverse general economic conditions including prolonged recessionary periods that might negatively impact natural gas demand and the capital markets; and

	•		unfavorable movements in natural gas prices in certain supply and demand areas.

A substantial portion of our revenues are generated from transportation contracts that must be renegotiated periodically.

Our revenues are generated under transportation and storage contracts which expire periodically and must be renegotiated, extended or replaced. If we are unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, we could suffer a material reduction in our revenues, earnings and cash flows. Currently, a substantial portion of our firm transportation contacts are subscribed through mid-2010. For additional information on the expiration of our contract portfolio, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. In particular, our ability to extend and replace contracts could be adversely affected by factors we cannot control, including:

	•		competition by other pipelines, including the change in rates or upstream supply of existing pipeline competitors, as well as the proposed construction by other companies of additional pipeline capacity or LNG terminals in markets served by our interstate pipeline;

	•		changes in state regulation of local distribution companies, which may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire;

	•		reduced demand and market conditions in the areas we serve;

	•		the availability of alternative energy sources or natural gas supply points; and

	•		legislative and/or regulatory actions.

In 2008, our contracts with Atlanta Gas Light Company, Southern Company Services, Alabama Gas Corporation and SCANA Corporation represented approximately 27 percent, 11 percent, 10 percent and 8 percent of our firm transportation capacity. For additional information regarding our major customers, see Item 1, Business — Markets and Competition. The loss of one of these customers or a decline in their creditworthiness could adversely affect our results of operations, financial position and cash flows.

We are exposed to the credit risk of our customers and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk of delays in payment as well as losses resulting from nonpayment and/or nonperformance by our customers, including default risk associated with adverse economic conditions. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of our existing or future customers, and they fail to pay and/or perform due to an unanticipated deterioration in their creditworthiness and we are unable to remarket the capacity, our business, the results of our operations and our financial condition could be adversely affected. We may not be able to effectively re-market capacity during and after insolvency proceedings involving a shipper.

Fluctuations in energy commodity prices could adversely affect our business.

Revenues generated by our transportation and storage contracts depend on volumes and rates, both of which can be affected by the price of natural gas. Increased prices could result in a reduction of the volumes transported by our customers, including power companies that may not dispatch natural gas-fired power plants if natural gas prices

increase. Increased prices could also result in industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies’ loss of customer base. The success of our transmission and storage operations is subject to continued development of additional gas supplies to offset the natural decline from existing wells connected to our system, which requires the development of additional oil and natural gas reserves and obtaining additional supplies from interconnecting pipelines. A decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission and storage through our system.

We retain a fixed percentage of natural gas received for transportation and storage as provided in our tariff. This retained natural gas is used as fuel and to replace lost and unaccounted for natural gas. As calculated in a manner set forth in our tariff, any revenues generated from any excess natural gas retained and not burned are shared with our customers on an annual basis. Any under recoveries are our responsibility. If natural gas prices in the supply basins connected to our pipeline system are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted on a short-term basis, as well as with respect to our long-term recontracting activities. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact our transportation revenues. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our financial condition, results of operations and liquidity. Fluctuations in energy prices are caused by a number of factors, including:

	•		regional, domestic and international supply and demand;

	•		availability and adequacy of transportation facilities;

	•		energy legislation and regulation;

	•		federal and state taxes, if any, on the sale or transportation and storage of natural gas;

	•		abundance of supplies of alternative energy sources; and

	•		political unrest among countries producing oil and LNG.

The agencies that regulate us and our customers could affect our profitability.

Our business is regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of the Interior and various state and local regulatory agencies whose actions have the potential to adversely affect our profitability. In particular, the FERC regulates the rates we are permitted to charge our customers for our services and sets authorized rates of return. Under the terms of our last rate settlement, we are obligated to file proposed new rates to be effective no later than October 1, 2010. We anticipate filing a new rate case no later than March 2009 with revised rates expected to become effective September 1, 2009.

In addition, in April 2008, the FERC adopted a new policy that will allow master limited partnerships to be included in rate of return proxy groups for determining rates for services provided by interstate natural gas and oil pipelines. The FERC uses a discounted cash flow model that incorporates the use of proxy groups to develop a range of reasonable returns earned on equity interests in companies with corresponding risks. The FERC then assigns a rate of return on equity within that range to reflect specific risks of that pipeline when compared to the proxy group companies. The FERC’s policy statement concludes among other items that (i) there should be no cap on the level of distributions included in the current discounted cash flow methodology and (ii) there should be a downward adjustment to the long-term growth rate used for the equity cost of capital of natural gas pipeline master limited partnerships. Pursuant to the FERC’s jurisdiction over rates, existing rates may be challenged by complaint, and proposed rate increases may be challenged by protest. A successful complaint or protest against our rates could have an adverse impact on our revenues.

In a January 15, 2009 decision that discussed an individual pipeline’s rate of return, the FERC analyzed the operations of each company proposed for inclusion in that pipeline’s proxy group to determine whether each company to be included had commensurate risks to the pipeline whose rates were being determined. The FERC included in that proxy group two primarily gas pipeline master limited partnerships (with the adjusted gross domestic product) and a diversified company that had higher risk exploration, production and trading operations in addition to pipeline operations. Companies whose distribution, electric or natural gas liquids operations exceeded pipeline operations were excluded. In light of this, it is expected that pipeline returns on equity will be driven largely by fact-based proxy group determinations in each case.

The FERC currently allows partnerships and other pass through entities to include in their cost-of-service an income tax allowance. Any changes to the FERC’s treatment of income tax allowances in cost-of-service and to potential adjustment in a future rate case of our equity rate of return may cause our rates to be set at a level that is different from those currently in place and in some instances lower than the level otherwise in effect.

Also, increased regulatory requirements relating to the integrity of our pipeline requires additional spending in order to maintain compliance with these requirements. Any additional requirements that are enacted could significantly increase the amount of these expenditures. Further, state agencies that regulate our local distribution company customers could impose requirements that could impact demand for our services.

Environmental compliance and remediation costs and the costs of environmental liabilities could exceed our estimates.

Our operations are subject to various environmental laws and regulations regarding compliance and remediation obligations. Compliance obligations can result in significant costs to install and maintain pollution controls, fines and penalties resulting from any failure to comply and potential limitations on our operations. Remediation obligations can result in significant costs associated with the investigation or clean up of contaminated properties (some of which have been designated as Superfund sites by the U.S. Environmental Protection Agency (EPA) under the Comprehensive Environmental Response, Compensation and Liability Act), as well as damage claims arising out of the contamination of properties or impact on natural resources. Although we believe we have established appropriate reserves for our environmental liabilities, it is not possible for us to estimate the exact amount and timing of all future expenditures related to environmental matters and we could be required to set aside additional amounts which could significantly impact our future consolidated results of operations, financial position or cash flows. See Part II, Item 8, Financial Statements and Supplementary Data, Note 7.

In estimating our environmental liabilities, we face uncertainties that include:

	•		estimating pollution control and clean up costs, including sites where preliminary site investigation or assessments have been completed;

	•		discovering new sites or additional information at existing sites;

	•		receiving regulatory approval for remediation programs;

	•		quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties;

	•		evaluating and understanding environmental laws and regulations, including their interpretation and enforcement; and

	•		changing environmental laws and regulations that may increase our costs.

In addition to potentially increasing the cost of our environmental liabilities, changing environmental laws and regulations may increase our future compliance costs, such as the costs of complying with ozone standards and potential mandatory greenhouse gas reporting and emission reductions. Future environmental compliance costs relating to greenhouse gases (GHGs) associated with our operations are not yet clear. Legislative and regulatory measures to address GHG emissions are in various phases of discussions or implementation at the international, national, regional and state levels. Various federal and state legislative proposals have been made over the last several years and it is possible that legislation may be enacted in the future that could negatively impact our operations and financial results. The level of such impact will likely depend upon whether any of our facilities will be directly responsible for compliance with GHG regulations and legislation; whether federal legislation will preempt any potentially conflicting state/regional GHG programs; whether cost containment measures will be available; the ability to recover compliance costs from our customers; and the manner in which allowances are provided. At the federal regulatory level, the EPA has requested public comments on the potential regulation of GHGs under the Clean Air Act. Some of the regulatory alternatives identified by the EPA in its request for comments, if eventually promulgated as final rules, would likely impact our operations and financial results. It is uncertain whether the EPA will proceed with adopting final rules or whether the regulation of GHGs will be addressed in federal and state legislation. Legislation and regulation are also in various stages of discussion or implementation in many of the states and regions in which we operate. Therefore, it is not yet possible to determine whether the regulations implementing the legislation will be material to our operations or our financial results.

Finally, several lawsuits have been filed seeking to force the federal government to regulate GHG emissions and individual companies to reduce the GHG emissions from their operations. These and other lawsuits may also result in decisions by federal and state courts and agencies that impact our operations and ability to obtain certifications and permits to construct future projects.

Although it is uncertain what impact these legislative, regulatory, and judicial actions might have on us until further definition is provided in those forums, there is a risk that such future measures could result in changes to our operations and to the consumption and demand for natural gas. Changes to our operations could include increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, (iii) construct new facilities, (iv) acquire allowances to authorize our GHG emissions, (v) pay any taxes related to our GHG emissions and (vi) administer and manage a GHG emissions program. While we may be able to include some or all of the costs associated with our environmental liabilities and environmental and GHG compliance in the rates charged by our pipeline and in the prices at which we sell natural gas, our ability to recover such costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final regulations and legislation.

Our operations are subject to operational hazards and uninsured risks.

Our operations are subject to the inherent risks normally associated with pipeline operations, including pipeline ruptures, explosions, pollution, release of toxic substances, fires, adverse weather conditions (such as hurricanes and flooding), terrorist activity or acts of aggression, and other hazards. Each of these risks could result in damage to or destruction of our facilities or damages or injuries to persons and property causing us to suffer substantial losses. Analyses performed by various governmental and private organizations indicate potential physical risks associated with climate change events (such as flooding, etc). Some of the studies indicate that potential impacts on energy infrastructure are highly uncertain and not well understood, including both the timing and potential magnitude of such impacts. As the science is better understood and analyzed, we will review the operational and uninsured risks to our facilities attributed to climate change.

While we maintain insurance against many of these risks to the extent and in amounts that we believe are reasonable, our insurance coverages have material deductibles as well as limits on our maximum recovery, and do not cover all risks. In addition, there is a risk that our insurers may default on their coverage obligations. As a result, our results of operations, cash flows or financial condition could be adversely affected if a significant event occurs that is not fully covered by insurance.

The expansion of our business by constructing new facilities subjects us to construction and other risks that may adversely affect our financial results.

We may expand the capacity of our existing pipeline and storage facilities by constructing additional facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:

	•		our ability to obtain necessary approvals and permits by the FERC and other regulatory agencies on a timely basis and on terms that are acceptable to us;

	•		the ability to access sufficient capital at reasonable rates to fund expansion projects, especially in periods of prolonged economic decline when we may be unable to access the capital markets;

	•		the availability of skilled labor, equipment, and materials to complete expansion projects;

	•		potential changes in federal, state and local statutes, regulations and orders, including environmental requirements that prevent a project from proceeding or increase the anticipated cost of the project;

	•		impediments on our ability to acquire rights-of-way or land rights on a timely basis or on terms that are acceptable to us;

	•		our ability to construct projects within anticipated costs, including the risk that we may incur cost overruns resulting from inflation or increased costs of equipment, materials, labor, contractor productivity or other

			factors beyond our control, that we may not be able to recover from our customers which may be material;

	•		the lack of future growth in natural gas supply and/or demand; and

	•		the lack of transportation, storage or throughput commitments.

Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. There is also the risk that the downturn in the economy and its negative impact upon natural gas demand may result in either slower development in our expansion projects or adjustments in the contractual commitments supporting such projects. As a result, new facilities may be delayed or may not achieve our expected investment return, which could adversely affect our results of operations, cash flows or financial position.

Adverse general domestic economic conditions could negatively affect our operating results, financial condition, or liquidity.

We, El Paso, and its subsidiaries are subject to the risks arising from adverse changes in general domestic economic conditions including recession or economic slowdown. Recently, the U.S. economy has experienced recession and the financial markets have experienced extreme volatility and instability. In response to the volatility in the financial markets, El Paso has also announced certain actions that are designed to reduce its need to access such financial markets, including reductions in the capital programs of certain of its operating subsidiaries and the sale of several non-core assets.

If we or El Paso experience prolonged periods of recession or slowed economic growth in the United States, demand growth from consumers for natural gas transported by us may continue to decrease, which could impact the development of our future expansion projects. Additionally, our or El Paso’s access to capital could continue to be impeded and the cost of capital we obtain could be higher. Finally, we are subject to the risks arising from changes in legislation and regulation associated with any such recession or prolonged economic slowdown, including creating preference for renewables, as part of a legislative package to stimulate the economy. Any of these events, which are beyond our control, could negatively impact our business, results of operations, financial condition, and liquidity.

We are subject to financing and interest rate risk.

Our future success, financial condition and liquidity could be adversely affected based on our ability to access capital markets and obtain financing at cost effective rates. This is dependent on a number of factors in addition to general economic conditions discussed above, many of which we cannot control, including changes in:

	•		our credit ratings;

	•		the structured and commercial financial markets;

	•		market perceptions of us or the natural gas and energy industry; and

	•		market prices for hydrocarbon products.

Risks Related to Our Affiliation with El Paso and the MLP

El Paso and its MLP file reports, proxy statements and other information with the SEC under the Securities Exchange Act of 1934, as amended. Each prospective investor should consider this information and the matters disclosed therein in addition to the matters described in this report. Such information is not included herein or incorporated by reference into this report.

We are a majority owned subsidiary of El Paso.

As a majority owned subsidiary of El Paso, subject to limitations in our indentures, El Paso has substantial control over:

	•		decisions on our financing and capital raising activities;

	•		mergers or other business combinations;

	•		our acquisitions or dispositions of assets; and

	•		our participation in El Paso’s cash management program.

El Paso may exercise such control in its interests and not necessarily in the interests of us or the holders of our long-term debt.

Our business requires the retention and recruitment of a skilled workforce and the loss of employees could result in the failure to implement our business plan.

Our business requires the retention and recruitment of a skilled workforce. If El Paso is unable to retain and recruit employees such as engineers and other technical personnel, our business could be negatively impacted.

Our relationship with El Paso and its financial condition subjects us to potential risks that are beyond our control.

Due to our relationship with El Paso, adverse developments or announcements concerning El Paso or its other subsidiaries could adversely affect our financial condition, even if we have not suffered any similar development. The ratings assigned to El Paso’s senior unsecured indebtedness are below investment grade, currently rated Ba3 by Moody’s Investor Service, BB- by Standard & Poor’s and BB+ by Fitch Ratings. The ratings assigned to our senior unsecured indebtedness are currently investment grade, with a Baa3 rating by Moody’s Investor Service and a BBB- rating by Fitch Ratings. Standard & Poor’s has assigned a below investment grade rating of BB to our senior unsecured indebtedness. El Paso and its subsidiaries, including us, are (i) on a stable outlook with Moody’s Investor Service and Fitch Ratings and (ii) on a negative outlook with Standard & Poor’s. There is a risk that these credit ratings may be adversely affected in the future as the credit rating agencies continue to review our and El Paso’s leverage, liquidity, and credit profile. Any reduction in our or El Paso’s credit ratings could impact our ability to access the capital markets, as well as our cost of capital.

El Paso provides cash management and other corporate services for us. We are currently required to make distributions of available cash as defined in our partnership agreement on a quarterly basis to our partners. In addition, we conduct commercial transactions with some of our affiliates. If El Paso or such affiliates are unable to meet their respective liquidity needs, we may not be able to access cash under the cash management program, or our affiliates may not be able to pay their obligations to us. However, we might still be required to satisfy any affiliated payables we have established. Our inability to recover any affiliated receivables owed to us could adversely affect our financial position and cash flows. For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 11.

Our relationship with El Paso and the MLP subjects us to potential conflicts of interest and they may favor their interests to the detriment of us.

Although El Paso has majority control of most decisions affecting our business, there are certain decisions that require the approval of both El Paso and the MLP, including material regulatory filings, any significant sale of our assets, mergers and certain changes in affiliated service agreements. Conflicts of interest or disagreements could arise between El Paso and the MLP with regard to such matters requiring unanimous approval, which could negatively impact our future operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

We have not included a response to this item since no response is required under Item 1B of Form 10K.

ITEM 2. PROPERTIES

A description of our properties is included in Item 1, Business, and is incorporated herein by reference.

We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interest in these properties or the use of these properties in our business. We believe that our properties are adequate and suitable for the conduct of our business in the future.

ITEM 3. LEGAL PROCEEDINGS

A description of our legal proceedings is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 7, and is incorporated herein by reference.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

All of our partnership interests are held by El Paso and the MLP and, accordingly, are not publicly traded. Prior to converting into a general partnership effective November 1, 2007, all of our common stock was held by El Paso.

We are required to make distributions to our partners of available cash as defined in our partnership agreement on a quarterly basis from legally available funds that have been approved for payment by our Management Committee. We made cash distributions to our partners of approximately $200 million in 2008. Additionally, in January 2009, we made a cash distribution of approximately $35 million to our partners. No dividends or cash distributions were declared or paid in 2007 or 2006.

ITEM 6. SELECTED FINANCIAL DATA

The following selected historical financial data should be read together with Item 7, Management’s Discussion and Analysis and Financial Condition and Results of Operations and Item 8, Financial Statements and Supplementary Data included in this Form 10-K. This information reflects our wholly owned subsidiaries, SLNG and Elba Express as discontinued operations for periods prior to their distribution. The information as of and for each of the years ended December 31, 2005, 2006, 2007 and 2008 was derived from our audited consolidated financial statements. The information as of and for the year ended December 31, 2004 was derived from unaudited financial statements. These selected historical results are not necessarily indicative of results to be expected in the future.


	As of or for the Year Ended December 31,
	2008		2007		2006		2005		2004
	(In millions)
Operating Results Data:
Operating revenues	$	540	$	482	$	462	$	437	$	485
Operating income		271		242		218		215		230
Income from continuing operations		235		202		162		155		154

Financial Position Data:
Total assets	$	2,629	$	2,803	$	3,395	$	3,199	$	2,972
Total long-term debt, less current maturities		910		1,098		1,096		1,195		1,195
Partners’ capital/stockholder’s equity		1,577		1,542		1,644		1,455		1,279


ITEM 7.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Our Management’s Discussion and Analysis (MD&A) should be read in conjunction with our consolidated financial statements and the accompanying footnotes. MD&A includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from the statements we make. These risks and uncertainties are discussed further in Part I, Item 1A, Risk Factors. We have included a discussion in this MD&A of our business, growth projects, results of operations, liquidity, contractual obligations and critical accounting policies and estimates that may affect us as we operate in the future.

In November 2007, in conjunction with the formation of El Paso’s master limited partnership (MLP), we distributed our 50 percent interest in Citrus Corp. (Citrus) and our wholly owned subsidiaries Southern LNG, Inc. (SLNG) and Elba Express, to El Paso. Citrus owns the Florida Gas Transmission Company, LLC pipeline system and SLNG owns the Elba Island LNG facility. SLNG and Elba Express have been reflected as discontinued operations in our financial statements for periods prior to their distribution. Our continuing operating results include earnings from Citrus, but only through the date of its distribution to El Paso. For a further discussion of these discontinued operations, see Item 8, Financial Statements and Supplementary Data, Note 2. In addition, effective November 1, 2007, we converted our legal structure into a general partnership, and are no longer subject to income taxes. Accordingly, we settled our then existing current and deferred tax balances through El Paso’s cash management program pursuant to our tax sharing agreement with El Paso.

Overview

Business. Our primary business consists of the interstate transportation and storage of natural gas. Each of these businesses faces varying degrees of competition from other existing and proposed pipelines and LNG facilities, as well as from alternative energy sources used to generate electricity, such as hydroelectric power, coal and fuel oil. Our revenues from transportation and storage services consist of the following types.


⁽¹⁾		Total revenues include both tariff-based revenues as well as other revenues. Our tariff-based revenues are 89 percent reservation and 11 percent usage and other. Other non-tariff based revenues include liquids transportation revenue and amounts associated with retained fuel.

⁽²⁾		Revenues exclude revenue from the contract settlement associated with the Calpine bankruptcy due to the non-recurring nature of this item.

The FERC regulates the rates we can charge our customers. These rates are generally a function of the cost of providing services to our customers, including a reasonable return on our invested capital. Under the terms of our last rate settlement, we are obligated to file proposed new rates to be effective no later than October 1, 2010. We anticipate filing a new rate case no later than March 2009 with revised rates expected to become effective September 1, 2009. Because of our regulated nature and the high percentage of our revenues attributable to reservation charges, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices, changes in supply and demand, regulatory actions, competition, declines in the creditworthiness of our customers and weather.

We continue to manage our recontracting process to mitigate the risk of significant impacts on our revenues from expiring contracts. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs, although at times, we enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive. Our existing contracts mature at various times and in varying amounts of throughput capacity. The weighted average remaining contract term for our active contracts is approximately five years as of December 31, 2008. Below are the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2008, including those with terms beginning in 2009 or later.


			Percent of Total		Reservation		Percent of Total
	BBtu/d		Contracted Capacity		Revenue		Reservation Revenue
					(In millions)
2009		177		5	$	7		2
2010		1,069		28		119		31
2011		696		18		65		17
2012		343		9		36		9
2013 and beyond		1,480		40		160		41

Total		3,765		100	$	387		100

Growth Projects. We expect to spend approximately $562 million on contracted organic growth projects from 2009 through 2013. Of this amount, we expect to spend $106 million in 2009. These expenditures are primarily related to the Cypress Phase III, the South System III and the Southeast Supply Header projects.

	•		Cypress Phase III. The Cypress Phase III expansion project will add 20,700 horsepower of additional compression and approximately 160 MMcf/d of additional capacity at an estimated cost of $86 million. A FERC certificate has been issued for the project. Construction of Cypress Phase III is at the option of BG LNG Services. If BG LNG Services elects to have us build Cypress Phase III, then construction is expected to commence in 2010 with an in-service date in the first half of 2011. If constructed, Cypress Phase III would be fully subscribed by BG LNG Services with a contract through December 2030.

	•		South System III. The South System III expansion project will expand our pipeline system in Mississippi, Alabama and Georgia by adding approximately 81 miles of pipeline looping and replacement on our south system and 17,310 horsepower of compression to serve an existing power generation facility in the Atlanta, Georgia area that is being converted from coal-fired to cleaner burning natural gas owned by the Southern Company. This expansion project will be completed in three phases, with each phase expected to add an additional 122 MMcf/d of capacity. During the second quarter of 2008, we changed the scope of this project at the request of the customer which increased the total estimated cost to $352 million. We have entered into a precedent agreement with Southern Company Services as agent for its affiliated operating companies, Georgia Power Company, Alabama Power Company, Mississippi Power Company, Southern Power Company and Gulf Power Company to provide an incremental firm transportation service to such operating companies, commencing in phases beginning January 1, 2011, for a term of 15 years. The precedent agreement obligates us to proceed with the South System III expansion project, upon the occurrence of certain conditions precedent, including FERC approval of the project on our system and the proposed Southeast Supply Header project described below. We filed with the FERC in December 2008 for certificate authorization to construct and operate these facilities. The project has estimated in-service dates of January 2011 for Phase I, June 2011 for Phase II and June 2012 for Phase III.

•

Southeast Supply Header. We own an undivided interest in the northern portion of the Southeast Supply Header project jointly owned by Spectra Energy Corp (Spectra) and CenterPoint Energy, which added a 115-mile supply line to the western portion of our system. This project is expected to provide access through pipeline interconnects to several supply basins, including the Barnett Shale, Bossier Sands, Arkoma and Fayetteville Shale basins. The estimated cost to us for this project is $241 million. This project is expected to be completed in two phases, with the first phase having provided us with approximately 140 MMcf/d of additional supply capacity, and the second phase expected to provide us with an additional 350 MMcf/d of supply capacity. Phase I of the project was placed in service in September 2008. In December 2008, we filed an application with the FERC for certificate authorization to construct Phase II, which is anticipated to be placed in service in June 2011.

We believe that cash flows from operating activities combined with amounts available to us under El Paso’s cash management program or contributions from our partners, will be adequate to meet our capital requirements and our existing operating needs.

Results of Operations

Our management uses earnings before interest expense and income taxes (EBIT) as a measure to assess the operating results and effectiveness of our business, which consists of consolidated operations as well as investments in unconsolidated affiliates. We believe EBIT is useful to investors because it allows them to evaluate more effectively our operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income adjusted for (i) items that do not impact our income from continuing operations, such as discontinued operations, (ii) income taxes (prior to conversion to a partnership), (iii) interest and debt expense and (iv) affiliated interest income. We exclude interest and debt expense from this measure so that investors may evaluate our operating results without regard to our financing methods. EBIT may not be comparable to measurements used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flows. Below is a reconciliation of our EBIT to net income, our throughput volumes and an analysis and discussion of our results in 2008 compared with 2007 and 2007 compared with 2006.

Operating Results:


	2008			2007			2006
	(In millions, except for volumes)
Operating revenues	$	540		$	482		$	462
Operating expenses		(269	)		(240	)		(244	)

Operating income		271			242			218
Earnings from unconsolidated affiliates		13			88			78
Other income, net		10			13			8

EBIT		294			343			304
Interest and debt expense		(72	)		(91	)		(95	)
Affiliated interest income		13			19			18
Income taxes		—			(69	)		(65	)

Income from continuing operations		235			202			162
Discontinued operations, net of income taxes		—			19			22

Net income	$	235		$	221		$	184

Throughput volumes (BBtu/d)⁽¹⁾		2,339			2,345			2,167



⁽¹⁾		Throughput volumes include billable transportation throughput volumes for storage injection.

EBIT Analysis:


	2008 to 2007											2007 to 2006
									EBIT												EBIT
	Revenue		Expense			Other			Impact			Revenue			Expense			Other			Impact
	Favorable/(Unfavorable)
	(In millions)
Expansions	$	14	$	(2	)	$	(2	)	$	10		$	26		$	(2	)	$	4		$	28
Service revenues		2		—			—			2			(6	)		—			—			(6	)
Gas not used in operations and other natural gas sales		9		(12	)		—			(3	)		(1	)		(4	)		—			(5	)
Calpine bankruptcy		33		—			—			33			—			—			—			—
Operating and general and administrative expenses		—		(10	)		—			(10	)		—			6			—			6
Impact of Hurricane Katrina		—		—			—			—			—			8			—			8
Earnings from Citrus		—		—			(75	)		(75	)		—			—			13			13
Other⁽¹⁾		—		(5	)		(1	)		(6	)		1			(4	)		(2	)		(5	)

Total impact on EBIT	$	58	$	(29	)	$	(78	)	$	(49	)	$	20			4		$	15		$	39


⁽¹⁾		Consists of individually insignificant items.

Expansions. We have completed two of the three phases of our Cypress project. In May 2007, we placed Phase I of the project in service, and in May 2008 we placed Phase II in service. This resulted in increasing levels of revenue throughout 2008 and 2007 and a decrease in allowance for funds used during construction (AFUDC) on this project in 2008. Additionally, we incurred higher AFUDC during 2008 related to the construction of Phase I of the Southeast Supply Header, which was placed into service in September.

Service Revenues. During 2008, our service revenues increased primarily due to an increase in our firm transportation revenue offset by lower interruptible services and usage revenue. During 2007, our service revenues decreased primarily due to two firm transportation contracts that expired and were not renewed offset by higher revenues from interruptible services due to throughput increases during 2007.

Gas Not Used in Operations and Other Natural Gas Sales. Our tariff provides for a fuel sharing where we may retain certain gas quantities associated with fuel efficiencies as discussed further herein. Our tariff provides for a recovery mechanism for costs associated with imbalances. The financial impacts of operational gas, net of gas used in operations, is based on the price of natural gas and the amount of natural gas we are allowed to retain and dispose of according to our tariff, relative to the amounts of natural gas we use for operating purposes and the cost of operating our electric compression facilities. Our share of retained gas not used in operations results in revenues to us, which are impacted by volumes and prices during a given period. During the year ended December 31, 2008, our EBIT was lower primarily due to higher cost of electric compression on our system and lower gas prices at year end. During the year ended December 31, 2007, our EBIT decreased primarily due to lower net retained volumes and higher costs of operating our electric compression facilities.

Calpine Bankruptcy. During 2008, we recognized revenue related to distributions received under Calpine’s approved plan of reorganization. For further information on the Calpine bankruptcy, see Item 8, Financial Statements and Supplementary Data, Note 7.

Operating and General and Administrative Expenses. Our operating and general and administrative costs were higher in 2008 than 2007, primarily due to higher repair and maintenance costs and higher allocated costs from El Paso based on the estimated level of resources devoted to us and the relative size of our EBIT, gross property and payroll when compared to El Paso’s other affiliates. Our operating general and administrative costs were lower in 2007 than 2006, primarily due to lower repair and maintenance costs, partially offset by higher allocated costs from El Paso.

Impact of Hurricane Katrina. During 2007, we incurred lower operation and maintenance expenses to repair damage caused by Hurricane Katrina as compared to the same period in 2006.

Earnings from Citrus. In November 2007, in conjunction with the formation of El Paso’s MLP, we distributed our 50 percent interest in Citrus to El Paso. As a result, we no longer record equity earnings from Citrus. Our operating results for 2007 reflect earnings from Citrus prior to its distribution to El Paso in November 2007. During 2007, our equity earnings on our Citrus investment increased primarily due to (i) a favorable settlement of approximately $8 million for litigation brought against Spectra LNG Sales (formerly Duke Energy LNG Sales, Inc.) for the wrongful termination of a gas supply contract; (ii) Citrus’ sale of a receivable for approximately $3 million related to the bankruptcy of Enron North America and (iii) favorable operating results of approximately $8 million from FGT due to higher system usage and lower operating costs.

Interest and Debt Expense

Interest and debt expense for the year ended December 31, 2008, was $19 million lower than in 2007 primarily due to lower average outstanding debt balances. Interest and debt expense for the year ended December 31, 2007, was $4 million lower than in 2006 primarily due to a reduction in the weighted average interest rate of our outstanding fixed rate debt. For further information on our outstanding debt balances, see Item 8, Financial Statements and Supplementary Data, Note 6.

Affiliated Interest Income

Affiliated interest income was $13 million in 2008 which decreased from $19 million in 2007 and $18 million in 2006 due to lower average advances due from El Paso under its cash management program and lower short-term interest rates. The following table shows the average advances due from El Paso and the average short-term interest rates for the year ended December 31:


	2008			2007			2006
	(In millions, except for rates)
Average advance due from El Paso	$	300		$	315		$	320
Average short-term interest rate		4.4	%		6.2	%		5.7	%

Income Taxes

Effective November 1, 2007, we no longer pay income taxes as a result of our conversion into a partnership, which impacted our 2007 effective tax rate. Our effective tax rates of 25 percent for the year ended December 31, 2007, and 29 percent for the year ended December 31, 2006 were lower than the statutory rate of 35 percent primarily due to the tax effect of earnings from unconsolidated affiliates that qualify for the dividends received deduction, partially offset by the effect of state income taxes. For a reconciliation of the statutory rate to the effective tax rates, see Item 8, Financial Statements and Supplementary Data, Note 3.

Liquidity and Capital Resources

Liquidity Overview. Our primary sources of liquidity are cash flows from operating activities and El Paso’s cash management program and capital contributions from our partners. Our primary uses of cash are for working capital, capital expenditures, debt service requirements and for required distributions to our partners. We are required to make distributions of available cash as defined in our partnership agreement on a quarterly basis to our partners. We have historically advanced cash to El Paso under its cash management program, which we reflect in investing activities in our statement of cash flows. At December 31, 2008, we had a note receivable from El Paso of approximately $136 million of which approximately $41 million was classified as current based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. See Item 8, Financial Statements and Supplementary Data, Note 11, for a further discussion of El Paso’s cash management program. We believe that cash flows from operating activities combined with amounts available to us under El Paso’s cash management program or contributions from our partners, will be adequate to meet our capital requirements and our existing operating needs.

Extreme volatility in the financial markets, the energy industry and the global economy will likely continue through 2009. The global financial markets remain extremely volatile and it is uncertain whether recent U.S. and foreign government actions will successfully restore confidence and liquidity in the global financial markets. This could impact our longer-term access to capital for future growth projects as well as the cost of such capital. Based on the liquidity available to us through our operating activities, El Paso’s cash management program and capital contributions from our partners, we do not anticipate having a need to directly access the financial markets in 2009 for any of our operating activities or expansion capital needs. Additionally, although the impacts are difficult to quantify at this point, a downward trend in the global economy could have adverse impacts on natural gas consumption and demand. However, we believe our exposure to changes in natural gas consumption and demand is largely mitigated by a revenue base that is significantly comprised of long term contracts that are based on firm demand charges and are less affected by a potential reduction in the actual usage or consumption of natural gas.

As of December 31, 2008, El Paso had approximately $1.0 billion of cash and approximately $1.2 billion of capacity available to it under various committed credit facilities. In light of the current economic climate and in response to the financial market volatility, El Paso, since November 2008, has generated approximately$1.2 billion of additional liquidity through three separate note offerings and has obtained additional revolving credit facility capacity and letter of credit capacity. Although we do not anticipate to directly access the financial markets, the volatility in the financial markets could impact our or El Paso’s ability to access these markets at reasonable rates in the future.

For further detail on our risk factors including adverse general economic conditions and our ability to access financial markets which could impact our operations and liquidity, see Part 1, Item 1A, Risk Factors.

2008 Cash Flow Activities. Our cash flows for the years ended December 31 were as follows:


	2008			2007
	(In millions)
Cash flows from continuing operating activities	$	285		$	(51	)
Cash flows from continuing investing activities		151			(395	)
Cash flows from continuing financing activities		(436	)		446

	•		Operating Activities. For the year ended December 31, 2008 as compared to the same period in 2007, cash flow from operating activities was higher primarily as a result of settling our then existing current and deferred tax balances of approximately $334 million through the cash management program upon converting our legal structure into a general partnership effective November 1, 2007. Also contributing to this increase were the proceeds received from the Calpine bankruptcy and the impact of expansion projects placed in service during 2007 and 2008.

	•		Investing Activities. Most of the change in investing activities in 2008 can be attributed to activity under El Paso’s cash management program and capital expenditures. In 2008, we used approximately $236 million of the recoveries of our notes receivable from El Paso under its cash management program to

repurchase debt as part of our previously announced debt repurchases. We also had lower capital expenditures in 2008 primarily related to the completion of our Cypress Phase I project in 2007. Our capital expenditures for the years ended December 31 were as follows:


	2008		2007
	(In millions)
Maintenance	$	63	$	93
Expansion/Other		71		158
Hurricanes⁽¹⁾		4		(8	)

Total	$	138	$	243


⁽¹⁾		Amounts shown are net of insurance proceeds of $5 million and $21 million in 2008 and 2007, respectively.

			Under our current plan for 2009, we have budgeted to spend (i) approximately $74 million for capital expenditures to maintain the integrity of our pipeline, to comply with clean air regulations and to ensure the safe and reliable delivery of natural gas to our customers and (ii) approximately $100 million to expand the capacity and services of our pipeline and storage system.

	•		Financing Activities. In 2008, we retired $34 million of our 6.125% notes due in 2008 and paid $202 million, including premiums, to repurchase approximately $189 million of our notes as part of our previously announced debt repurchases. We repurchased these notes with recoveries of our notes receivable from El Paso under its cash management program. Additionally, we are required to make distributions of available cash as defined in our partnership agreement on a quarterly basis to our partners. During 2008, we paid cash distributions of approximately $200 million to our partners. In January 2009, we made a cash distribution of approximately $35 million to our partners.

Contractual Obligations

We are party to various contractual obligations. A portion of these obligations are reflected in our financial statements, such as long-term debt and other accrued liabilities, while other obligations, such as operating leases, demand charges under transportation and storage commitments and capital commitments, are not reflected on our balance sheet. We have excluded from these amounts expected contributions to our other postretirement benefit plans, because these expected contributions are not contractually required. For further information on our expected contributions to our post retirement benefit plans, see Item 8, Financial Statements and Supplementary Data, Note 8. The following table and discussion summarizes our contractual cash obligations as of December 31, 2008, for each of the periods presented (all amounts are undiscounted):


	Due in		Due in		Due in
	less than 1 Year		1 to 3 Years		3 to 5 Years		Thereafter		Total
	(In millions)
Long-term debt:
Principal	$	—	$	—	$	—	$	911	$	911
Interest		61		123		123		682		989

Operating leases		2		6		6		11		25
Other contractual commitments and purchase obligations:
Transportation and storage commitments		9		—		—		—		9
Other commitments		1		2		1		—		4

Total contractual obligations	$	73	$	131	$	130	$	1,604	$	1,938

Long-Term Debt (Principal and Interest). Debt obligations represent stated maturities. Interest payments are shown through the stated maturity date of the related fixed rate debt based on the contractual interest rate. For a further discussion of our debt obligations, see Item 8, Financial Statements and Supplementary Data, Note 6.

Operating Leases. For a further discussion of these obligations see Item 8, Financial Statements and Supplementary Data, Note 7.

Other Contractual Commitments and Purchase Obligations. Other contractual commitments and purchase obligations are defined as legally enforceable agreements to purchase goods or services that have fixed or minimum quantities and fixed or minimum variable price provisions, and that detail approximate timing of the underlying obligations. Included are the following:

	•		Transportation and Storage Commitments. Included in these amounts are commitments for demand charges for firm access to natural gas transportation and storage capacity.

	•		Other Commitments. Included in these amounts are commitments for electric service to provide power to certain of our compression facilities. We have excluded asset retirement obligations and reserves for litigation and environmental remediation as these liabilities are not contractually fixed as to timing and amount.

Commitments and Contingencies

For a discussion of our commitments and contingencies, see Item 8, Financial Statements and Supplementary Data, Note 7, which is incorporated herein by reference.

Off-Balance Sheet Arrangements

For a discussion of our off-balance sheet arrangements, see Item 8, Financial Statements and Supplementary Data, Notes 7 and 11, which are incorporated herein by reference.

Critical Accounting Policies and Estimates

The accounting policies discussed below are considered by management to be critical to an understanding of our financial statements as their application places the most significant demands on management’s judgment. Due to the inherent uncertainties involved with this type of judgment, actual results could differ significantly from estimates and may have a material impact on our results of operations. For additional information concerning our other accounting policies, please read the notes to the financial statements included in Item 8, Financial Statements and Supplementary Data, Note 1.

Cost-Based Regulation. We account for our regulated operations under the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. The economic effects of regulation can result in a regulated company recording assets for costs that have been or are expected to be approved for recovery from customers or recording liabilities for amounts that are expected to be returned to customers in the rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Management regularly assesses whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. We periodically evaluate the applicability of SFAS No. 71, and consider factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, we may have to reduce certain of our asset balances to reflect a market basis lower than cost and write-off the associated regulatory assets.

Accounting for Other Postretirement Benefits. We reflect an asset or liability for our postretirement benefit plan based on its over funded or under funded status. As of December 31, 2008, our postretirement benefit plan was under funded by $15 million. Our postretirement benefit obligation and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligation. We select our discount rate by matching the timing and amount of our expected future benefit payments for our postretirement benefit obligation to the average yields of various high-quality bonds with corresponding maturities.

Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligation, along with changes to the plan and other items, are deferred and recorded as either a regulatory asset or liability. The following table shows the impact of a one percent change in the primary assumptions used in our actuarial calculations associated with our postretirement benefits for the year ended December 31, 2008 (in millions):


				Change in Funded
				Status and Pretax
				Accumulated Other
	Net Benefit			Comprehensive
	Expense (Income)			Income
One percent increase in:
Discount rates	$	—		$	5
Expected return on plan assets		(1	)		—
Health care cost trends		1			(5	)
One percent decrease in:
Discount rates	$	—		$	(5	)
Expected return on plan assets⁽¹⁾		1			—
Health care cost trends		(1	)		5


(1)		If the actual return on plan assets was one percent lower than the expected return on plan assets, our expected cash contributions to our postretirement benefit plan would not significantly change.

New Accounting Pronouncements Issued But Not Yet Adopted

See Item 8, Financial Statements and Supplementary Data, Note 1, under New Accounting Pronouncements Issued But Not Yet Adopted, which is incorporated herein by reference.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to the risk of changing interest rates. At December 31, 2008, we had a note receivable from El Paso of approximately $136 million, with a variable interest rate of 3.2% that is due upon demand. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates its carrying value due to the market-based nature of its interest rate and the fact that it is a demand note.

The table below shows the carrying value and related weighted-average effective interest rates on our non-affiliated fixed rate long-term debt securities estimated based on quoted market prices for the same or similar issues.


	December 31, 2008
	Expected Fiscal Year of Maturity of									December 31, 2007
	Carrying Amounts							Fair		Carrying		Fair
	2009-2013		Thereafter			Total		Value		Amount		Value
	(In millions, except for rates)
Liabilities:
Long-term debt — fixed rate	$	—	$	910		$	910	$	726	$	1,132	$	1,187
Average effective interest rate				6.7	%

We are also exposed to risks associated with changes in natural gas prices on natural gas that we are allowed to retain, net of gas used in operations. Retained natural gas is used as fuel and to replace lost and unaccounted for natural gas. We are at risk if we retain less natural gas than needed for these purposes. Pricing volatility may also impact the value of under or over recoveries of retained natural gas, imbalances and system encroachments.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by SEC rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. It consists of policies and procedures that:

	•		Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

	•		Provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

	•		Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Under the supervision and with the participation of management, including the President and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2008. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2008.

Report of Independent Registered Public Accounting Firm

The Partners of Southern Natural Gas Company

We have audited the accompanying consolidated balance sheets of Southern Natural Gas Company (the Company) as of December 31, 2008 and 2007, and the related consolidated statements of income and comprehensive income, partners’ capital/stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule listed in the Index at Item 15(a) for each of the three years in the period ended December 31, 2008. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. The consolidated financial statements of Citrus Corp. and Subsidiaries (a corporation in which the Company had a 50% interest), have been audited by other auditors whose report has been furnished to us, and our opinion on the consolidated financial statements, insofar as it relates to the amounts included from Citrus Corp. and Subsidiaries, is based solely on the report of the other auditors, exclusive of the income adjustment related to the disposition of the equity interest in November 2007. In the consolidated financial statements, the Company’s investment in Citrus Corp. and Subsidiaries represents approximately 18% of total assets as of December 31, 2006, and earnings from this investment represent approximately 28% and 24% of income before income taxes for the years ended December 31, 2007 and 2006, respectively.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Southern Natural Gas Company at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2007, the Company adopted the provisions of Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No. 109, and effective December 31, 2006 and January 1, 2008, the Company adopted the recognition and measurement date provisions, respectively, of Statement of Financial Accounting Standards No. 158, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106, and 132 (R).

/s/ Ernst & Young LLP

Houston, Texas
February 26, 2009

SOUTHERN NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS
(In millions)


	December 31,
	2008		2007
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Accounts and notes receivable
Customer		3		5
Affiliates		71		89
Other		2		1
Materials and supplies		14		12
Other		15		11

Total current assets		105		118

Property, plant and equipment, at cost		3,636		3,448
Less accumulated depreciation and amortization		1,373		1,298

Total property, plant and equipment, net		2,263		2,150

Other assets
Investments in unconsolidated affiliates		81		84
Note receivable from affiliate		95		378
Other		85		73

		261		535

Total assets	$	2,629	$	2,803


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable
Trade	$	28	$	29
Affiliates		10		3
Other		18		16
Current maturities of long-term debt		—		34
Taxes payable		8		11
Accrued interest		18		24
Other		10		10

Total current liabilities		92		127

Long-term debt, less current maturities		910		1,098


Other liabilities		50		36


Commitments and contingencies (Note 7)
Partners’ capital		1,577		1,542

Total liabilities and partners’ capital	$	2,629	$	2,803

See accompanying notes.

SOUTHERN NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)


	Year Ended December 31,
	2008			2007			2006
Cash flows from operating activities
Net income	$	235		$	221		$	184
Less income from discontinued operations, net of income taxes		—			19			22

Income from continuing operations		235			202			162
Adjustments to reconcile net income to net cash from operating activities
Depreciation and amortization		53			53			49
Deferred income taxes		—			23			34
Earnings from unconsolidated affiliates, adjusted for cash distributions		3			42			2
Other non-cash income items		(5	)		(6	)		(2	)
Asset and liability changes
Accounts receivable		13			(7	)		21
Accounts payable		7			(13	)		(6	)
Taxes payable		—			(21	)		(20	)
Other current assets		(5	)		5			(3	)
Other current liabilities		(9	)		(4	)		(6	)
Non current assets		(11	)		(5	)		(10	)
Non current liabilities		4			(320	)		2

Cash provided by (used in) continuing activities		285			(51	)		223
Cash provided by discontinued activities		—			25			35

Net cash provided by (used in) operating activities		285			(26	)		258

Cash flows from investing activities
Additions to property, plant and equipment		(138	)		(243	)		(273	)
Net change in notes receivable from affiliate		289			(152	)		57
Proceeds from the sale of assets		—			—			3

Cash provided by (used in) continuing activities		151			(395	)		(213	)
Cash used in discontinued activities		—			(25	)		(45	)

Net cash provided by (used in) investing activities		151			(420	)		(258	)

Cash flows from financing activities
Payments to retire long-term debt		(236	)		(584	)		—
Distributions to partners		(200	)		—			—
Net proceeds from issuance of long-term debt		—			494			—
Contribution from parent		—			536			—
Contribution to discontinued operations		—			—			(10	)

Cash provided by (used in) continuing activities		(436	)		446			(10	)
Cash provided by discontinued activities		—			—			10

Net cash provided by (used in) financing activities		(436	)		446			—


Net change in cash and cash equivalents		—			—			—
Cash and cash equivalents
Beginning of period		—			—			—

End of period	$	—		$	—		$	—

See accompanying notes.

SOUTHERN NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL/STOCKHOLDER’S EQUITY
(In millions, except share amounts)


												Accumulated
						Additional						Other			Total			Total
	Common stock					Paid-in			Retained			Comprehensive			Stockholder’s			Partners’
	Shares			Amount		Capital			Earnings			Income (Loss)			Equity			Capital
January 1, 2006		1,000		$	—	$	340		$	1,120		$	(6	)	$	1,454		$	—
Net income										184						184
Other comprehensive income													1			1			—
Adoption of SFAS No. 158, net of income taxes of $2													5			5			—

December 31, 2006		1,000			—		340			1,304			—			1,644			—
Net income										187						187
Other comprehensive income													1			1			—
Adoption of FIN No. 48, net of income taxes of $(3)										(5	)					(5	)		—
Reclassification to regulatory liability (Note 8)							—						(5	)		(5	)		—

October 31, 2007		1,000			—		340			1,486			(4	)		1,822			—
Conversion to general partnership (November 1, 2007)		(1,000	)				(340	)		(1,486	)		4			(1,822	)		1,822
Contributions																			536
Distributions																			(850	)
Net income																			34

December 31, 2007		—			—		—			—			—			—			1,542
Net income																			235
Distributions																			(200	)

December 31, 2008		—		$	—	$	—		$	—		$	—		$	—		$	1,577

See accompanying notes.

SOUTHERN NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

We are a Delaware general partnership, originally formed in 1935 as a corporation. We are owned 75 percent by El Paso SNG Holding Company, L.L.C., a subsidiary of El Paso Corporation (El Paso) and 25 percent by EPPP SNG GP Holdings, L.L.C., a subsidiary of El Paso Pipeline Partners, L.P. (MLP) which is majority owned by El Paso. In conjunction with the formation of El Paso’s MLP in November 2007, we distributed our 50 percent interest in Citrus Corp. (Citrus), our wholly owned subsidiaries Southern LNG, Inc. (SLNG) and Elba Express Company, LLC (Elba Express) to El Paso effective November 21, 2007. Citrus owns the Florida Gas Transmission Company, LLC (FGT) pipeline system and SLNG owns our Elba Island LNG facility. We have reflected the SLNG and Elba Express operations as discontinued operations in our financial statements for periods prior to their distribution. Additionally, effective November 1, 2007, we converted to a general partnership and are no longer subject to income taxes and settled our current and deferred income tax balances through El Paso’s cash management program. For a further discussion of these and other related transactions, see Notes 2, 3 and 11.

Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (GAAP) and include the accounts of all majority owned and controlled subsidiaries after the elimination of intercompany accounts and transactions.

We consolidate entities when we either (i) have the ability to control the operating and financial decisions and policies of that entity or (ii) are allocated a majority of the entity’s losses and/or returns through our variable interests in that entity. The determination of our ability to control or exert significant influence over an entity and whether we are allocated a majority of the entity’s losses and/or returns involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control, the policies and decisions of an entity and where we are not allocated a majority of the entity’s losses and/or returns. We use the cost method of accounting where we are unable to exert significant influence over the entity.

Use of Estimates

The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates.

Regulated Operations

Our natural gas pipeline and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We follow the regulatory accounting principles prescribed under Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. Under SFAS No. 71, we record regulatory assets and liabilities that would not be recorded under GAAP for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Items to which we apply regulatory accounting requirements include certain postretirement employee benefit plan costs, loss on reacquired debt, an equity return component on regulated capital projects and certain costs included in, or expected to be included in, future rates.

Cash and Cash Equivalents

We consider short-term investments with an original maturity of less than three months to be cash equivalents.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable and for natural gas imbalances due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. We regularly review collectibility and establish or adjust our allowance as necessary using the specific identification method.

Materials and Supplies

We value materials and supplies at the lower of cost or market value with cost determined using the average cost method.

Natural Gas Imbalances

Natural gas imbalances occur when the actual amount of natural gas received on a customer’s contract at the supply point differs from the actual amount of natural gas delivered under the customer’s transportation contract at the delivery point. We value imbalances due to or from shippers at specified index prices set forth in our tariff based on the production month in which the imbalances occur. Customer imbalances are aggregated and netted on a monthly basis, and settled in cash, subject to the terms of our tariff. For differences in value between the amounts we pay or receive for the purchase or sale of natural gas used to resolve shipper imbalances over the course of a year, we have the right under our tariff to recover applicable losses or refund applicable gains through a storage cost reconciliation charge. This charge is applied to volumes as they are transported on our system. Annually, we true-up any losses or gains obtained during the year by adjusting the following years’ storage cost reconciliation charge.

Imbalances due from others are reported in our balance sheet as either accounts receivable from customers or accounts receivable from affiliates. Imbalances owed to others are reported on the balance sheet as either trade accounts payable or accounts payable to affiliates. We classify all imbalances as current as we expect to settle them within a year.

Property, Plant and Equipment

Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at the fair value of the assets acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead, interest and an equity return component, as allowed by the FERC. We capitalize major units of property replacements or improvements and expense minor items.

We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. We apply the FERC-accepted depreciation rate to the total cost of the group until its net book value equals its salvage value. Currently, our depreciation rates vary from less than one percent to 20 percent per year. Using these rates, the remaining depreciable lives of these assets range from 3 to 43 years. We re-evaluate depreciation rates each time we file with the FERC for a change in our transportation and storage rates.

When we retire property, plant and equipment, we charge accumulated depreciation and amortization for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less their salvage value. We do not recognize a gain or loss unless we sell or retire an entire operating unit. We include gains or losses on dispositions of operating units in operating income.

At December 31, 2008 and 2007, we had $48 million and $102 million of construction work in progress included in our property, plant and equipment.

We capitalize a carrying cost (an allowance for funds used during construction) on debt and equity funds related to our construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on our average cost of debt. Interest costs on debt amounts capitalized during the years ended December 31, 2008, 2007 and 2006, were $3 million, $4 million and $3 million. These debt amounts are included as a reduction to interest and debt expense on our income statement. The equity portion of capitalized costs is calculated using the most recent FERC-approved equity rate of return. The equity amounts capitalized (exclusive of taxes) during the years ended December 31, 2008, 2007 and 2006, were $7 million, $8 million and $5 million. These equity amounts are included as other non-operating income on our income statement.

Asset and Investment Impairments

We evaluate assets and investments for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset or investment and adverse changes in the legal or business environment such as adverse actions by regulators. When an event occurs, we evaluate the recoverability of our long-lived assets carrying values based on either (i) the long-lived asset’s ability to generate future cash flows on an undiscounted basis or (ii) the fair value of the investment in an unconsolidated affiliate. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of the asset downward, if necessary, to its estimated fair value. Our fair value estimates are generally based on market data obtained through the sales process or an analysis of expected discounted cash flows. The magnitude of any impairment is impacted by a number of factors, including the nature of the assets being sold and our established time frame for completing the sale, among other factors.

We reclassify the asset (or groups of assets) to be sold as either held-for-sale or as discontinued operations, depending on, among other criteria, whether we will have significant long-term continuing involvement with those assets after they are sold. We cease depreciating assets in the period that they are reclassified as either held for sale or as discontinued operations.

Revenue Recognition

Our revenues are primarily generated from natural gas transportation and storage services. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation and storage services, we recognize reservation revenues on firm contracted capacity ratably over the contract period regardless of the amount of natural gas that is transported or stored. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. Gas not used in operations is based on the volumes of natural gas we are allowed to retain and dispose of relative to the amounts we use for operating purposes. As calculated in a manner set forth in our tariff, any revenues generated from any excess natural gas retained and not burned are shared with our customers on an annual basis. We recognize our share of revenues on gas not used in operations from our shippers when we retain the volumes at the market prices required under our tariffs. We are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a rate proceeding. We establish reserves for these potential refunds.

Environmental Costs and Other Contingencies

Environmental Costs. We record liabilities at their undiscounted amounts on our balance sheet as other current and long-term liabilities when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.

We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our balance sheet.

Other Contingencies. We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.

Income Taxes

Effective November 1, 2007, we converted to a general partnership in conjunction with the formation of El Paso’s MLP and accordingly, we are no longer subject to income taxes. As a result of our conversion to a general partnership, we settled our existing current and deferred tax balances with recoveries of note receivables from El Paso under its cash management program pursuant to our tax sharing agreement with El Paso (see Notes 3 and 11). Prior to that date, we recorded current income taxes based on our taxable income and provided for deferred income taxes to reflect estimated future tax payments and receipts. Deferred taxes represented the income tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We accounted for tax credits under the flow-through method, which reduced the provision for income taxes in the year the tax credits first became available. We reduced deferred tax assets by a valuation allowance when, based on our estimates, it was more likely than not that a portion of those assets would not be realized in a future period.

On January 1, 2007, we adopted Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB No. 109. The adoption of FIN No. 48 did not have a material impact on our financial statements.

Accounting for Asset Retirement Obligations

We account for our asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and FIN No. 47, Accounting for Conditional Asset Retirement Obligations. We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred. Our asset retirement liabilities are recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the long-lived asset to which that liability relates. An ongoing expense is also recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation and amortization expense in our income statement. We have the ability to recover certain of these costs from our customers and have recorded an asset (rather than expense) associated with the depreciation of the property, plant and equipment and accretion of the liabilities described above.

We have legal obligations associated with our natural gas pipeline and related transmission facilities and storage wells. We have obligations to plug storage wells when we no longer plan to use them and when we abandon them. Our legal obligations associated with our natural gas transmission facilities relate primarily to purging and sealing the pipeline if it is abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are replaced. We are required to operate and maintain our natural gas pipeline and storage system, and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that the substantial majority of our natural gas pipeline and storage system assets have indeterminate lives. As of December 31, 2008, we had asset retirement liabilities of $20 million primarily related to pipelines we plan to abandon, and we report this amount on our balance sheet in other non-current liabilities. Our asset retirement liabilities as of December 31, 2007 were not material to our financial statements. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.

Postretirement Benefits

We maintain a postretirement benefit plan covering certain of our former employees. This plan requires us to make contributions to fund the benefits to be paid out under the plan. These contributions are invested until the benefits are paid out to plan participants. We record the net benefit cost related to this plan in our income statement. This net benefit cost is a function of many factors including benefits earned during the year by plan participants (which is a function of the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to our postretirement plan, see Note 8.

Effective December 31, 2006, we began accounting for our postretirement benefit plan under the recognition provisions of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an Amendment of FASB Statements No. 87, 88, 106, and 132(R) and recorded a $5 million increase, net of income taxes of $2 million, to accumulated other comprehensive income related to the adoption of this standard. Under SFAS No. 158, we record an asset or liability for our postretirement benefit plan based on its over funded or under funded status. In March 2007, the FERC issued guidance requiring regulated pipeline companies to record a regulatory asset or liability for any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions that would otherwise be recorded in accumulated other comprehensive income for non-regulated entities. Upon adoption of this FERC guidance, we reclassified $5 million from accumulated other comprehensive income to a regulatory liability.

Effective January 1, 2008, we adopted the measurement date provisions of SFAS No. 158 and changed the measurement date of our postretirement benefit plan from September 30 to December 31. The adoption of the measurement date provisions of this standard did not have a material impact on our financial statements.

New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2008, the following accounting standards had not yet been adopted by us.

Fair Value Measurements. We have adopted the provisions of SFAS No. 157, Fair Value Measurements in measuring the fair value of financial assets and liabilities in the financial statements. We have elected to defer the adoption of SFAS No. 157 for certain of our non-financial assets and liabilities until January 1, 2009, the adoption of which will not have a material impact on our financial statements.

Business Combinations. In December 2007, the FASB issued SFAS No. 141(R), Business Combinations, which provides revised guidance on the accounting for acquisitions of businesses. This standard changes the current guidance to require that all acquired assets, liabilities, minority interest and certain contingencies be measured at fair value, and certain other acquisition-related costs be expensed rather than capitalized. SFAS No. 141(R) will apply to acquisitions that are effective after December 31, 2008, and application of the standard to acquisitions prior to that date is not permitted.

Noncontrolling Interests. In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, which provides guidance on the presentation of minority interest, subsequently renamed “noncontrolling interest,” in the financial statements. This standard requires that noncontrolling interest be presented as a separate component of equity rather than as a “mezzanine” item between liabilities and equity, and also requires that noncontrolling interest be presented as a separate caption in the income statement. This standard also requires all transactions with noncontrolling interest holders, including the issuance and repurchase of noncontrolling interests, be accounted for as equity transactions unless a change in control of the subsidiary occurs. We will adopt the provisions of this standard effective January 1, 2009. The adoption of this standard will not have a material impact on our financial statements.

2. Divestitures

In November 2007, in conjunction with the formation of El Paso’s MLP, we distributed our wholly owned subsidiaries SLNG and Elba Express to El Paso. We have reflected these operations as discontinued operations in our financial statements for periods prior to their distribution. We also distributed our investment in Citrus to El Paso which is not reflected in discontinued operations. The table below summarizes the operating results of our discontinued operations for each of the two years ended December 31, 2007 and 2006.


	2007			2006
	(In millions)
Revenues	$	61		$	66
Costs and expenses		(35	)		(32	)
Other income, net		4			1
Interest and debt expense		1			1

Income before income taxes		31			36
Income taxes		12			14

Income from discontinued operations, net of income taxes	$	19		$	22

3. Income Taxes

In conjunction with the formation of El Paso’s MLP, we converted our legal structure into a general partnership effective November 1, 2007 and settled our current and deferred tax balances pursuant to our tax sharing agreement with El Paso with recoveries of note receivables from El Paso under its cash management program. The tables below reflect that these balances have been settled and that we no longer pay income taxes effective November 1, 2007.

Components of Income Taxes. The following table reflects the components of income taxes included in income from continuing operations for each of the two years ended December 31, 2007 and 2006:


	2007		2006
	(In millions)
Current
Federal	$	40	$	30
State		6		1

		46		31

Deferred
Federal		19		29
State		4		5

		23		34

Total income taxes	$	69	$	65

Effective Tax Rate Reconciliation. Our income taxes, included in income from continuing operations, differ from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons for each of the two years ended December 31, 2007 and 2006:


	2007			2006
	(In millions, except for rates)
Income taxes at the statutory federal rate of 35%	$	95		$	79
Increase (decrease)
Pretax income not subject to income tax after conversion to partnership		(11	)		—
State income taxes, net of federal income tax benefit		6			4
Earnings from unconsolidated affiliates where we anticipate receiving dividends		(21	)		(17	)
Other		—			(1	)

Income taxes	$	69		$	65

Effective tax rate		25	%		29	%

4. Financial Instruments

At December 31, 2008 and 2007, the carrying amounts of cash and cash equivalents and trade receivables and payables are representative of their fair value because of the short-term maturity of these instruments. At December 31, 2008 and 2007, we had an interest bearing note receivable from El Paso of approximately $136 million and $425 million due upon demand, with a variable interest rate of 3.2% and 6.5%. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates its carrying value due to the market-based nature of its interest rate and the fact that it is a demand note.

In addition, the carrying amounts and estimated fair values of our long-term debt are based on quoted market prices for the same or similar issues and are as follows at December 31:


	2008				2007
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(In millions)
Long-term debt, including current maturities	$	910	$	726	$	1,132	$	1,187

5. Regulatory Assets and Liabilities

Below are the details of our regulatory assets and liabilities at December 31:


	2008		2007
	(In millions)
Current regulatory assets	$	1	$	—

Non-current regulatory assets
Taxes on capitalized funds used during construction		34		31
Unamortized loss on reacquired debt		36		24
Other		4		3

Total non-current regulatory assets		74		58

Total regulatory assets	$	75	$	58


Non-current regulatory liabilities
Cost of removal of offshore assets	$	4	$	7
Postretirement benefits		—		23

Total non-current regulatory liabilities	$	4	$	30

6. Debt and Credit Facilities

Debt. Our long-term debt consisted of the following at December 31:


	2008		2007
	(In millions)
6.125% Notes due September 2008	$	—	$	34
5.90% Notes due April 2017		500		500
7.35% Notes due February 2031		153		300
8.0% Notes due March 2032		258		300

		911		1,134
Less: Current maturities		—		34
Unamortized discount		1		2

Total long-term debt, less current maturities	$	910	$	1,098

In September 2008, we retired $34 million of our 6.125% notes due 2008. In June 2008, we paid $202 million, including premiums, to repurchase approximately $147 million of our 7.35% notes due 2031 and $42 million of our 8.0% notes due 2032 as part of our previously announced debt repurchases. We repurchased these notes with recoveries of our notes receivable from El Paso under its cash management program.

Under our indentures, we are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions. For the year ended December 31, 2008, we were in compliance with our debt-related covenants. Our long-term debt contains cross-acceleration provisions, the most restrictive of which is a $10 million cross-acceleration clause. If triggered, repayment of the long-term debt that contains these provisions could be accelerated.

7. Commitments and Contingencies

Legal Proceedings

Gas Measurement Cases. We and a number of our affiliates were named defendants in actions that generally allege mismeasurement of natural gas volumes and/or heating content resulting in the underpayment of royalties. These cases were filed in 1997 by an individual under the False Claims Act and have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming). These complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands. In October 2006, the U.S. District Judge issued an order dismissing all claims against all defendants. An appeal has been filed.

In addition to the above proceedings, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters, including those discussed above, cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. At December 31, 2008, we accrued approximately $2 million for our outstanding legal matters.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. At December 31, 2008, we had accrued approximately $1 million for expected remediation costs and associated onsite, offsite and groundwater technical studies. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued.

It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.

Regulatory Matters

Notice of Proposed Rulemaking. In October 2007, the Minerals Management Service (MMS) issued a Notice of Proposed Rulemaking for Oil and Gas and Sulphur Operations in the Outer Continental Shelf (OCS) — Pipelines and Pipeline Rights-of-Way. If adopted, the proposed rules would substantially revise MMS OCS pipeline and rights-of-way regulations. The proposed rules would have the effect of: (1) increasing the financial obligations of entities, like us, which have pipelines and pipeline rights-of-way in the OCS; (2) increasing the regulatory requirements imposed on the operation and maintenance of existing pipelines and rights of way in the OCS; and (3) increasing the requirements and preconditions for obtaining new rights-of-way in the OCS.

Greenhouse Gas (GHG) Emissions. Legislative and regulatory measures to address GHG emissions are in various phases of discussions or implementation at the international, national, regional and state levels. In the United States, it is likely that federal legislation requiring GHG controls will be enacted in the next few years. In addition, the EPA is considering initiating a rulemaking to regulate GHGs under the Clean Air Act. Legislation and regulation are also in various stages of discussions or implementation in many of the states in which we operate. Additionally, lawsuits have been filed seeking to force the federal government to regulate GHG emissions and individual companies to reduce GHG emissions from their operations. These and other lawsuits may result in decisions by state and federal courts and agencies that could impact our operations and ability to obtain certifications and permits to construct future projects. Our costs and legal exposure related to GHG regulations are not currently determinable.

Rate Case. Under the terms of our last rate settlement, we are obligated to file proposed new rates to be effective no later than October 1, 2010. We anticipate filing a new rate case no later than March 2009 with revised rates expected to become effective September 1, 2009.

Other Matters

Calpine Bankruptcy. In 2007, Calpine Corporation (Calpine) rejected its firm transportation contract with us which ran through 2019. Although our original undiscounted claim for this contract rejection was approximately $75 million, we entered into a settlement with Calpine under its plan of reorganization filed in June 2007 in connection with its bankruptcy proceeding. During the year of 2008, we recognized revenue of $35 million related to distributions received under Calpine’s approved plan of reorganization.

Commitments, Purchase Obligations and Other Matters

Commercial Commitments. We have entered into unconditional purchase obligations for products and services totaling approximately $13 million at December 31, 2008. Our annual obligations under these agreements are $10 million in 2009, and $1 million in each of 2010, 2011 and 2012. In addition, we have other planned capital and investment projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

Operating Leases and Other Commercial Commitments. We lease property, facilities and equipment under various operating leases. Our primary commitment under operating leases is the lease of our office space in Birmingham, Alabama. El Paso guarantees our obligations under these lease agreements. Minimum future annual rental commitments on our operating leases as of December 31, 2008, were as follows:


Year Ending
December 31,	(In millions)
2009	$	2
2010		3
2011		3
2012		3
2013		3
Thereafter		11

Total	$	25

Rent expense on our operating leases for each of the three years ended December 31, 2008, 2007 and 2006 was $4 million, less than $1 million, and $3 million. These amounts include our share of rent allocated to us from El Paso.

We hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline system. Currently, our obligations under these easements are not material to the results of our operations.

Guarantees. We are or have been involved in various ownership and other contractual arrangements that sometimes require us to provide additional financial support that results in the issuance of performance guarantees that are not recorded in our financial statements. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. As of December 31, 2008, we have a performance

guarantee related to contracts held by SLNG, an entity formerly owned by us, with a maximum exposure of $225 million and a performance guarantee related to contracts held by Elba Express, an entity formerly owned by us, with no stated maximum limit. We estimate our potential exposure related to these guarantees is approximately $631 million, which is based on their remaining estimated obligations under the contracts.

8. Retirement Benefits

Pension and Retirement Benefits. El Paso maintains a pension plan and a retirement savings plan covering substantially all of its U.S. employees, including our former employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, El Paso matches 75 percent of participant basic contributions up to six percent of eligible compensation and can make additional discretionary matching contributions depending on its performance relative to its peers. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.

Postretirement Benefits. We provide postretirement medical benefits for a closed group of retirees. These benefits may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs and El Paso reserves the right to change these benefits. Employees in this group who retire after June 30, 2000 continue to receive limited postretirement life insurance benefits. Our postretirement benefit plan costs are prefunded to the extent these costs are recoverable through our rates. To the extent actual costs differ from the amounts recovered in rates, a regulatory asset or liability is recorded. We expect to contribute $4 million to our postretirement benefit plan in 2009.

Effective December 31, 2006, we began accounting for our postretirement benefit plan under recognition provisions of SFAS No. 158. Under SFAS No. 158, we record an asset or liability for our postretirement benefit plan based on its over funded or under funded status. In March 2007, the FERC issued guidance requiring regulated pipeline companies to record a regulatory asset or liability for any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions that would otherwise be recorded in accumulated other comprehensive income for non-regulated entities. Upon adoption of this FERC guidance, we reclassified $5 million from accumulated other comprehensive income to a regulatory liability.

Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. The table below provides information about our postretirement benefit plan. In 2008, we adopted the measurement date provisions of SFAS 158 and the information below for 2008 is presented and computed as of and for the fifteen months ended December 31, 2008. For 2007, the information is presented and computed as of and for the twelve months ended September 30, 2007.


	December 31,			September 30,
	2008			2007
	(In millions)
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation — beginning of period	$	62		$	73
Interest cost		4			4
Participant contributions		1			1
Actuarial (gain) loss		1			(9	)
Benefits paid ⁽¹⁾		(7	)		(7	)

Accumulated postretirement benefit obligation — end of period	$	61		$	62


Change in plan assets:
Fair value of plan assets — beginning of period	$	66		$	59
Actual return on plan assets		(17	)		9
Employer contributions		4			4
Participant contributions		1			1
Benefits paid		(8	)		(7	)

Fair value of plan assets — end of period	$	46		$	66

Reconciliation of funded status:
Fair value of plan assets	$	46		$	66
Less: Accumulated postretirement benefit obligation		61			62
Fourth quarter contributions					—

Net asset (liability) at December 31	$	(15	)	$	4


⁽¹⁾		Amounts shown are net a subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

Plan Assets. The primary investment objective of our plan is to ensure that, over the long-term life of the plan, an adequate pool of sufficiently liquid assets exists to meet the benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles. Any shortfall of investment performance compared to investment objectives is the result of general economic and capital market conditions. As a result of the general decline in the markets for debt and equity securities, the fair value of our plan assets and the funded status of our other postretirement benefit plan declined during 2008, which resulted in a decrease in our plan assets and regulatory liability when our plan’s assets and obligation were remeasured at December 31, 2008. The following table provides the target and actual asset allocations in our postretirement benefit plan as of December 31, 2008 and September 30, 2007:


			Actual		Actual
Asset Category	Target		2008		2007
	(Percent)
Equity securities		65		65		63
Debt securities		35		34		33
Cash and cash equivalents		—		1		4

Total		100		100		100

Expected Payment of Future Benefits. As of December 31, 2008, we expect the following payments (net of participant contributions and an expected subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003) under our plan (in millions):


Year Ending
December 31,
2009	$	6
2010		6
2011		5
2012		5
2013		5
2014-2018		24

Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining our postretirement plan obligations for 2008, 2007 and 2006:


	2008		2007		2006
	(Percent)
Assumptions related to benefit obligations at December 31, 2008 and September 30, 2007 and 2006 measurement dates:
Discount rate		6.00		6.05		5.50
Assumptions related to benefit costs at December 31:
Discount rate		6.05		5.50		5.25
Expected return on plan assets⁽¹⁾		8.00		8.00		8.00


⁽¹⁾		The expected return on plan assets is a pre-tax rate of return based on our targeted portfolio of investments. Our postretirement benefit plan’s investment earnings are subject to unrelated business income tax at a rate of 35%. The expected return on plan assets for our postretirement benefit plans is calculated using the after-tax rate of return.

Actuarial estimates for our postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 8.6 percent in 2008, gradually decreasing to 5.0 percent by the year 2015. Changes in the assumed health care cost trends can have a significant effect on the amounts reported for our postretirement benefit plan. A one-percentage point change would not have had a significant effect on interest costs in 2008 or 2007. A one-percentage point change in assumed health care cost trends would have the following effects as of December 31, 2008 and 2007:


	2008			2007
	(In millions)
One percentage point increase:
Accumulated postretirement benefit obligation	$	5		$	5
One percentage point decrease:
Accumulated postretirement benefit obligation	$	(5	)	$	(4	)

Components of Net Benefit Cost. For each of the years ended December 31, the components of net benefit costs are as follows:


	2008			2007			2006
	(In millions)
Interest cost	$	4		$	4		$	4
Expected return on plan assets		(3	)		(3	)		(3	)
Amortization of net actuarial gain		(1	)		—			—

Net postretirement benefit cost	$	—		$	1		$	1

9. Transactions with Major Customers

The following table shows revenues from our major customers for each of the three years ended December 31:


	2008		2007		2006
	(In millions)
SCANA Corporation⁽¹⁾	$	79	$	77	$	71
Southern Company Services		55		54		53

⁽¹⁾

A significant portion of revenues received from a subsidiary of SCANA Corporation resulted from firm capacity released by Atlanta Gas Light Company under terms allowed by our tariff.

10. Supplemental Cash Flow Information

The following table contains supplemental cash flow information from continuing operations for each of the three years ended December 31:


	2008		2007			2006
	(In millions)
Interest paid, net of capitalized interest	$	75	$	97		$	95
Income tax payments		—		374	⁽¹⁾		53


⁽¹⁾		Includes amounts related to the settlement of current and deferred tax balances due to the conversion to a partnership in November 2007 (see Notes 3 and 11).

11. Investments in Unconsolidated Affiliates and Transactions with Affiliates

Investments in Unconsolidated Affiliates

Citrus. Prior to its transfer to El Paso in November 2007 in conjunction with the formation of El Paso’s MLP, we had a 50 ownership percent interest in Citrus, which owns the FGT pipeline system. CrossCountry Energy, LLC (CrossCountry), a subsidiary of Southern Union Company, owns the other 50 percent of Citrus. During 2007 and 2006, we received $103 million and $63 million in dividends from Citrus.

Bear Creek Storage Company (Bear Creek). We have a 50 percent ownership interest in Bear Creek, a joint venture with Tennessee Gas Storage Company, our affiliate. We account for our investment in Bear Creek using the equity method of accounting. Our investment in Bear Creek at December 31, 2008 and 2007 was $81 million and $84 million. During 2008, 2007 and 2006, we received $16 million, $27 million and $17 million in dividends from Bear Creek.

Summarized financial information of our proportionate share of our unconsolidated affiliates as of and for the years ended December 31 is presented as follows:


	2008		2007			2006
	(In millions)
Operating results data:⁽¹⁾
Operating revenues	$	20	$	267		$	262
Operating expenses		8		115			113
Income from continuing operations and net income		13		92	⁽²⁾		78


	2008		2007
	(In millions)
Financial position data:
Current assets	$	27	$	28
Non-current assets		55		58
Other current liabilities		1		2
Equity in net assets		81		84


⁽¹⁾		Includes Citrus results for the entire year ended December 31, 2007. Our share of Citrus’ net income prior to the distribution of this investment in November 2007 was $75 million, adjusted for the excess purchase price amortization.

⁽²⁾		The difference between our proportionate share of our equity investments’ net income and our earnings from unconsolidated affiliates in 2007 is due primarily to the excess purchase price amortization related to Citrus and differences between the estimated and actual equity earnings on our investments.

Transactions with Affiliates

MLP Acquisition. On September 30, 2008, El Paso’s MLP acquired an additional 15 percent ownership interest in us.

Contributions/Distributions. On November 21, 2007, in conjunction with the formation of the MLP, we made a distribution of our 50 percent ownership in Citrus and our wholly owned subsidiaries SLNG and Elba Express (described in Note 1) with a book value of approximately $850 million to El Paso and El Paso made a capital contribution of approximately $536 million to us.

We are required to make distributions of available cash as defined in our partnership agreement on a quarterly basis to our partners. During 2008, we paid cash distributions of approximately $200 million to our partners. In addition, in January 2009 we paid a cash distribution to our partners of approximately $35 million. We did not make any distributions to our partners during 2007.

Cash Management Program. We participate in El Paso’s cash management program which matches short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowings from outside sources. El Paso uses the cash management program to settle intercompany transactions between participating affiliates. We have historically advanced cash to El Paso in exchange for an affiliated note receivable that is due upon demand. At December 31, 2008 and 2007, we had a note receivable from El Paso of $136 million and $425 million. We classified $41 million and $47 million of this receivable as current on our balance sheets at December 31, 2008 and 2007, based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. The interest rate on our note at December 31, 2008 and 2007 was 3.2% and 6.5%.

Income Taxes. Effective November 1, 2007, we converted into a general partnership as discussed in Note 1 and settled our existing current and deferred tax balances of approximately $334 million pursuant to our tax sharing agreement with El Paso with recoveries of note receivables from El Paso under its cash management program. During 2007, we also settled $20 million with El Paso through its cash management program for certain tax attributes previously reflected as deferred income taxes in our financial statements. These settlements are reflected as operating activities in our statement of cash flows.

Accounts Receivable Sales Program. We sell certain accounts receivable to a qualifying special purpose entity (QSPE) under SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, whose purpose is solely to invest in our receivables. As of December 31, 2008 and 2007, we sold approximately $48 million and $59 million of receivable, received cash of approximately $24 million and $28 million and received subordinated beneficial interests of approximately $23 million and $30 million. In conjunction with the sale, the QSPE also issued senior beneficial interests on the receivables sold to a third party financial institution, which totaled $25 million and $28 million as of December 31, 2008 and 2007. We reflect the subordinated interest in receivables sold at their fair value on the date they are issued. These amounts (adjusted for subsequent collections), are recorded as accounts receivable from affiliate in our balance sheets. Our ability to recover our carrying value of our subordinated beneficial interests is based on the collectibility of the underlying receivables sold to the QSPE. We reflect accounts receivable sold under this program and changes in the subordinated beneficial interests as operating cash flows in our statement of cash flows. Under these agreements, we earn a fee for servicing the receivables and performing all administrative duties for the QSPE which is reflected as a reduction of operation and maintenance expense in our income statement. The fair value of these servicing and administrative agreements as well as the fees earned were not material to our financial statements for the years ended December 31, 2008 and 2007.

Affiliate Revenues and Expenses. We enter into transactions with our affiliates within the ordinary course of business and the services are based on the same terms as non-affiliates, including natural gas transportation services to affiliates under long-term contracts.

We do not have employees. Following our reorganization in November 2007, our former employees continue to provide services to us through an affiliated service company owned by our general partner, El Paso. We are managed and operated by officers of El Paso, our general partner. We have an omnibus agreement with El Paso and its affiliates under which we reimburse El Paso for the provision of various general and administrative services for our benefit and for direct expenses incurred by El Paso on our behalf. El Paso bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. In addition to allocations from El Paso, we are allocated costs from Tennessee Gas Pipeline Company, our affiliate, associated with our pipeline services. These allocations are based on the estimated level of effort devoted to our operations and the relative size of our EBIT, gross property and payroll.

The following table shows overall revenues and charges from our affiliates for each of the three years ended December 31:


	2008		2007		2006
	(In millions)
Revenues from affiliates	$	6	$	7	$	9
Operation and maintenance expenses from affiliates		107		69		65

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2008, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer, as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including our President and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objective and our President and Chief Financial Officer have concluded that our disclosure controls and procedures are effective at a reasonable level of assurance at December 31, 2008. See Item 8, Financial Statements and Supplementary Data under Management’s Annual Report on Internal Control Over Financial Reporting.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of 2008 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM 9A(T). CONTROLS AND PROCEDURES

This annual report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report. See Item 8, Financial Statements and Supplementary Data, under Management’s Annual Report on Internal Control Over Financial Reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Management Committee and Executive Officers

We are a Delaware general partnership with two partners, the first of which is a wholly owned subsidiary of El Paso (the “El Paso Partner”), and the second of which is a wholly owned subsidiary of the MLP (the “MLP Partner”). The El Paso Partner owns a 75 percent interest in our partnership, and the MLP Partner owns our remaining 25 percent interest. A general partnership agreement governs our ownership and management. Although our management is vested in its partners, the partners have agreed to delegate our management to a management committee. Decisions of or actions taken by the management committee are binding on us. The management committee is composed of four representatives, with three representatives being designated by the El Paso Partner and one representative being designated by the MLP Partner. Each member of the management committee has full authority to act on behalf of the partner that designated such member with respect to matters pertaining to us. Each member of the management committee is entitled to one vote on each matter submitted for a vote of the management committee, and the vote of a majority of the members of the management committee constitutes action of the management committee, except for certain actions specified in the general partnership agreement that require unanimous approval of the management committee. Our officers are appointed by the management committee.

The following provides biographical information for each of our executive officers and management committee members as of March 2, 2009.

There are no family relationships among any of our executive officers or management committee members, and, unless described herein, no arrangement or understanding exists between any executive officer and any other person pursuant to which he was or is to be selected as an officer.


Name	Age		Position
James C. Yardley		57	President and Management Committee Member

John R. Sult		49	Senior Vice President, Chief Financial Officer and Controller

Daniel B. Martin		52	Senior Vice President and Management Committee Member

Norman G. Holmes		52	Senior Vice President, Chief Commercial Officer and Management Committee Member

Michael J. Varagona		53	Vice President, Business Development and Management Committee Member

James C. Yardley. Mr. Yardley has been a member of the Management Committee of Southern Natural Gas Company since November 2007 and President since May 1998. Mr. Yardley previously served as Chairman of the Board of Southern Natural Gas Company from May 2005 to November 2007 and a director from November 2001 to November 2007. He has been Executive Vice President of our parent El Paso with responsibility for oversight of the regulated pipeline business unit since August 2006. Mr. Yardley has served as Vice President, Marketing and Business Development for Southern Natural Gas Company from April 1994 to April 1998. Prior to that time, Mr. Yardley worked in various capacities with Southern Natural Gas Company and Sonat Inc. beginning in 1978. Mr. Yardley serves as Director, President and Chief Executive Officer of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.

John R. Sult. Mr. Sult has been Senior Vice President, Chief Financial Officer and Controller of Southern Natural Gas Company since November 2005. Mr. Sult also serves as Senior Vice President and Controller of our parent El Paso and as Senior Vice President, Chief Financial Officer and Controller of our affiliates El Paso Natural Gas Company, Colorado Interstate Gas Company, and Tennessee Gas Pipeline Company. He held the position of Vice President and Controller at Halliburton Energy Services Company from August 2004 until joining El Paso in October 2005. From December 2002 to July 2004, Mr. Sult provided finance and accounting advisory services to energy companies as an independent consultant. He served as an audit partner for Arthur Andersen LLP from September 1994 to December 2002. Mr. Sult serves as Senior Vice President, Chief Financial Officer and Controller of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.

Daniel B. Martin. Mr. Martin has been a member of the Management Committee of Southern Natural Gas Company since November 2007 and Senior Vice President since June 2000. He previously served as a director of Southern Natural Gas Company from May 2005 to November 2007. Mr. Martin has been a director of our affiliates El Paso Natural Gas Company and Tennessee Gas Pipeline Company since May 2005. Mr. Martin has been Senior Vice President of Tennessee Gas Pipeline Company since June 2000 and Senior Vice President of El Paso Natural Gas Company since February 2000. He served as a director of ANR Pipeline Company from May 2005 through February 2007 and Senior Vice President of ANR Pipeline Company from January 2001 to February 2007. Prior to that time, Mr. Martin worked in various capacities with Tennessee Gas Pipeline Company beginning in 1978. Mr. Martin serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.

Norman G. Holmes. Mr. Holmes has been a member of the Management Committee of Southern Natural Gas Company since November 2007 and Senior Vice President and Chief Commercial Officer since August 2006. He previously served as a director of Southern Natural Gas Company from November 2005 to November 2007. Mr. Holmes served as Vice President, Business Development of Southern Natural Gas Company from 1999 to 2006 and as Vice President and Controller from 1995 to 1999. Prior to that time, Mr. Holmes worked in various capacities with Southern Natural Gas Company and Sonat, Inc. beginning in 1979. Mr. Holmes serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.

Michael J. Varagona. Mr. Varagona has been a member of the Management Committee of Southern Natural Gas Company since November 2007 and Vice President of Business Development since January 2007. Mr. Varagona served as Director, Business Development from January 2004 to December 2006. Prior to that time, Mr. Varagona worked in various capacities with Sonat, Inc. and El Paso beginning in 1978.

Audit Committee, Compensation Committee and Code of Ethics

As a majority owned subsidiary of El Paso, we rely on El Paso for certain support services. As a result, we do not have a separate corporate audit committee or audit committee financial expert, or a separate compensation committee. Also, we have not adopted a separate code of ethics. However, our executives are subject to El Paso’s code of ethics, referred to as the “Code of Business Conduct”. The Code of Business Conduct is a value-based code that is built on five core values: stewardship, integrity, safety, accountability and excellence. In addition to other matters, the Code of Business Conduct establishes policies to deter wrongdoing and to promote honest and ethical conduct, including ethical handling of actual or apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications and prompt internal reporting of violations of the Code of Business Conduct. A copy of the Code of Business Conduct is available for your review at El Paso’s website, www.elpaso.com. Copies will also be provided to any person upon request. Such requests should be in writing, addressed to El Paso Corporation, c/o Ms. Marguerite Woung-Chapman, Corporate Secretary, P.O. Box 2511, Houston, TX 77252.

ITEM 11. EXECUTIVE COMPENSATION

All of our executive officers are officers or employees of El Paso or one of its non-SNG subsidiaries and devote a substantial portion of their time to El Paso or such other subsidiaries. None of these executive officers receives any compensation from SNG or its subsidiaries. The compensation of our executive officers is set by El Paso, and we have no control over the compensation determination process. Our executive officers and former employees participate in employee benefit plans and arrangements sponsored by El Paso. We have not established separate employee benefit plans and we have not entered into employment agreements with any of our executive officers.

The members of our management committee are also officers or employees of El Paso or one of its non-SNG subsidiaries and do not receive additional compensation for their service as a member of our management committee.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

SNG is a Delaware general partnership. SNG is owned 75 percent indirectly through a wholly-owned subsidiary of El Paso, and is owned 25 percent by EPPP SNG GP Holdings, L.L.C., a subsidiary of El Paso Pipeline Partners, L.P., El Paso’s master limited partnership. The address of each of El Paso and El Paso Pipeline Partners, L.P. is 1001 Louisiana Street, Houston, Texas 77002.

The following table sets forth, as of February 23, 2009, the number of shares of common stock of El Paso owned by each of our executive officers and management committee members and all of our management committee members and executive officers as a group.

Shares of

Shares

Percentage of

Common

Underlying

Total Shares

Stock

Options

of Common

Owned

Exercisable

Stock

Directly or

Within

Beneficially

Name of Beneficial Owner

Indirectly

60 Days⁽¹⁾

Owned

Owned⁽²⁾

James C. Yardley

205,448

404,245

609,693

John R. Sult

64,945

94,607

159,552

Daniel B. Martin

132,437

263,701

396,138

Norman G. Holmes

54,728

172,271

226,999

Michael J. Varagona

33,238

55,669

88,907

All management committee members and executive officers as a group (5 persons)

490,796

990,493

1,481,289


*		Less than 1%.

⁽¹⁾		The shares indicated represent stock options granted under El Paso’s current or previous stock option plans, which are currently exercisable or which will become exercisable within 60 days of February 23, 2009. Shares subject to options cannot be voted.

⁽²⁾		Based on 698,613,542 shares outstanding as of February 23, 2009.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

We are a general partnership presently owned 75 percent indirectly through a wholly owned subsidiary of El Paso and 25 percent through a wholly owned subsidiary of the MLP.

SNG Guarantee of Elba Island Expansion

We formerly owned Southern LNG Inc. (SLNG), which owns and operates a LNG receiving and regasification terminal on Elba Island near Savannah, Georgia. SLNG is now a subsidiary of El Paso. In connection with an ongoing expansion of the Elba Island LNG terminal (Elba III), we have guaranteed necessary funds (up to a defined limit) to permit the construction of the Elba III expansion.

SNG Guarantee of Elba Express Expansion

SNG formerly owned Elba Express Pipeline Company, LLC (EEC), which is in the process of constructing a 191-mile pipeline primarily in Georgia. EEC is now a subsidiary of El Paso. We have agreed to provide, at our election, either all necessary funds to Elba Express (up to a defined limit) or a guarantee in the form of a performance bond (up to a defined limit) to permit the construction of the Elba Express pipeline.

El Paso Guarantee of SNG Lease

El Paso has guaranteed our obligations with respect to our leased headquarters.

Other Agreements and Transactions

In addition, we currently have and will have in the future other routine agreements with El Paso or one of its subsidiaries that arise in the ordinary course of business, including agreements for services and other transportation and exchange agreements and interconnection and balancing agreements with other El Paso pipelines.

For a description of certain additional affiliate transactions, see Part II, Item 8, Financial Statements and Supplementary Data, Note 11.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

The audit fees for the years ended December 31, 2008 and 2007 of $751,000 and $863,000, respectively, were primarily for professional services rendered by Ernst & Young LLP for the audits of the consolidated financial statements of Southern Natural Gas Company and its subsidiaries as well as the review of documents filed with the Securities and Exchange Commission, consents, and the issuance of comfort letters.

All Other Fees

No other audit-related, tax or other services were provided by our independent registered public accounting firm for the years ended December 31, 2008 and 2007.

Policy for Approval of Audit and Non-Audit Fees

We are substantially owned by El Paso and its subsidiaries and do not have a separate audit committee. El Paso’s Audit Committee has adopted a pre-approval policy for audit and non-audit services. For a description of El Paso’s pre-approval policies for audit and non-audit related services, see El Paso Corporation’s proxy statement for its 2009 Annual Meeting of Stockholders.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following consolidated financial statements are included in Part II, Item 8 of this report:

1. Financial Statements


	Page
Southern Natural Gas Company
Report of Independent Registered Public Accounting Firms		25
Consolidated Statements of Income and Comprehensive Income		26
Consolidated Balance Sheets		27
Consolidated Statements of Cash Flows		28
Consolidated Statements of Partners’ Capital/Stockholder’s Equity		29
Notes to Consolidated Financial Statements		30

2. Financial Statement Schedules

Schedule II — Valuation and Qualifying Accounts		45

All other schedules are omitted because they are not applicable, or the required information is disclosed in the financial statements or accompanying notes.

3. and (b). Exhibits

The Exhibit Index, which follows the signature page to this report and is hereby incorporated herein by reference, sets forth a list of those exhibits filed herewith, and includes and identifies contracts or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.


(c) Financial Statements of 50-Percent-Or-Less-Owned Investees:

Citrus Corp.
Report of Independent Registered Public Accounting Firm			52
Consolidated Balance Sheets			53
Consolidated Statements of Income			54
Consolidated Statements of Stockholders’ Equity			55
Consolidated Statements of Comprehensive Income			55
Consolidated Statements of Cash Flows			56
Notes to Consolidated Financial Statements			57

Undertaking

We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the U.S. SEC upon request all constituent instruments defining the rights of holders of our long-term debt and our consolidated subsidiaries not filed as an exhibit hereto for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of our total consolidated assets.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Citrus Corp.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of stockholders’ equity, of comprehensive income and of cash flows present fairly, in all material respects, the financial position of Citrus Corp. and subsidiaries (the “Company”) at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with the accounting principles generally accepted in the United States of America. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Notes 2 and 6 to the consolidated financial statements, the Company adopted the recognition and disclosure provisions of FASB Statement No. 158 “Employers’ Accounting for Defined Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R),” as of December 31, 2006.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
February 25, 2008

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,			December 31,
	2007			2006
	(In thousands)
ASSETS
Current Assets
Cash and cash equivalents	$	3,572		$	15,267
Accounts receivable, billed and unbilled, less allowances of $18 and $282, respectively		39,350			45,049
Materials and supplies		12,745			2,954
Exchange gas receivable		1,729			—
Other		2,248			1,025

Total Current Assets		59,644			64,295

Property, Plant and Equipment
Plant in service		4,265,844			4,163,082
Construction work in progress		150,742			85,746

		4,416,586			4,248,828
Less accumulated depreciation and amortization		1,401,638			1,304,133

Property, Plant and Equipment, Net		3,014,948			2,944,695

Other Assets
Unamortized debt expense		4,221			4,687
Regulatory assets		19,207			31,007
Other		10,838			76,429

Total Other Assets		34,266			112,123

Total Assets	$	3,108,858		$	3,121,113

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt	$	44,000		$	84,000
Accounts payable — trade and other		33,422			25,070
Accounts payable — affiliated companies		8,416			2,823
Accrued interest		14,251			14,805
Accrued income taxes		7,599			2,375
Accrued taxes, other than income		5,437			9,332
Exchange gas payable		22,547			24,225
Capital accruals		22,636			22,185
Dividends payable		42,600			—
Other		7,600			6,526

Total Current Liabilities		208,508			191,341

Deferred Credits
Deferred income taxes, net		763,364			777,404
Regulatory liabilities		14,842			14,256
Other		9,202			8,129

Total Deferred Credits		787,408			799,789

Long-Term Debt		909,810			836,882
Commitments and contingencies (Note 14)

Stockholders’ Equity
Common stock, $1 par value; 1,000 shares authorized, issued and outstanding		1			1
Additional paid-in capital		634,271			634,271
Accumulated other comprehensive loss		(7,885	)		(10,524	)
Retained earnings		576,745			669,353

Total Stockholders’ Equity		1,203,132			1,293,101

Total Liabilities and Stockholders’ Equity	$	3,108,858		$	3,121,113

The accompanying notes are an integral part of these consolidated financial statements.

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2007			2006			2005
	(In thousands)
Operating Revenues
Transportation of natural gas	$	495,513		$	485,189		$	476,049


Total Operating Revenues		495,513			485,189			476,049


Operating Expenses
Operations and maintenance		82,058			77,941			78,829
Depreciation and amortization		100,634			98,653			91,125
Taxes, other than income taxes		29,618			34,765			34,306


Total Operating Expenses		212,310			211,359			204,260


Operating Income		283,203			273,830			271,789


Other Income (Expenses)
Interest expense and related charges, net		(73,871	)		(76,428	)		(79,290	)
Other, net		39,984			4,633			6,531


Total Other Income (Expenses), net		(33,887	)		(71,795	)		(72,759	)


Income Before Income Taxes		249,316			202,035			199,030

Federal and State Income Tax Expense		92,224			75,960			75,086


Net Income	$	157,092		$	126,075		$	123,944

The accompanying notes are an integral part of these consolidated financial statements.

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2007			2006			2005
	(In thousands)
Common Stock
Balance, beginning and end of period	$	1		$	1		$	1


Additional Paid-in Capital
Balance, beginning and end of period		634,271			634,271			634,271


Accumulated Other Comprehensive Loss
Balance, beginning of period		(10,524	)		(13,162	)		(15,800	)
Recognition in earnings of previously deferred net losses related to derivative instruments used as cash flow hedges		2,639			2,638			2,638

Balance, end of period		(7,885	)		(10,524	)		(13,162	)


Retained Earnings
Balance, beginning of period		669,353			668,678			665,934
Net income		157,092			126,075			123,944
Dividends ⁽¹⁾		(249,700	)		(125,400	)		(121,200	)

Balance, end of period		576,745			669,353			668,678


Total Stockholders’ Equity	$	1,203,132		$	1,293,101		$	1,289,788

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Year Ended		Year Ended		Year Ended
	December 31,		December 31,		December 31,
	2007		2006		2005
	(In thousands)

Net income	$	157,092	$	126,075	$	123,944
Recognition in earnings of previously deferred net losses related to derivative instruments used as cash flow hedges		2,639		2,638		2,638

Total Comprehensive Income	$	159,731	$	128,713	$	126,582


(1)		Includes $42.6 million in Dividends Payable, declared in December 2007, payable in January, 2008 and which was paid on January 18, 2008. (See Note 7 — Related Party Transaction)

The accompanying notes are an integral part of these consolidated financial statements.

CITRUS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2007			2006			2005
	(In thousands)
Cash flows provided by operating activities

Net income	$	157,092		$	126,075		$	123,944
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		100,634			98,653			91,125
Amortization of hedge loss in other comprehensive income		2,639			2,638			2,638
Amortization of discount and swap hedge loss in long term debt		528			527			530
Amortization of regulatory assets and other deferred charges		1,250			3,274			3,380
Amortization of debt costs		994			1,048			1,053
Deferred income taxes		(12,277	)		18,629			12,740
Allowance for funds used during construction		(4,683	)		(1,630	)		(1,441	)
Gain on sale of assets		—			—			(1,236	)

Changes in operating assets and liabilities:
Accounts receivable		5,699			(3,327	)		403
Accounts payable		11,950			(3,316	)		(10,567	)
Accrued interest		(554	)		(286	)		(324	)
Accrued income tax		5,224			3,247			(7,204	)
Other current assets and liabilities		(8,944	)		18,749			3,234
Other long-term assets and liabilities		74,668			(24,627	)		36,140

Net cash provided by operating activities		334,220			239,654			254,415

Cash flows used in investing activities
Capital expenditures		(175,370	)		(106,023	)		(37,610	)
Allowance for funds used during construction		4,683			1,630			1,441
Proceeds from sale of assets		—			—			1,715

Net cash used in investing activities		(170,687	)		(104,393	)		(34,454	)

Cash flows used in financing activities
Dividends paid		(207,100	)		(125,400	)		(121,200	)
Net (payments) borrowings on the revolving credit facilities		76,400			(2,000	)		(75,000	)
Long-term debt finance costs		(528	)		—			—
Payments on long-term debt		(44,000	)		(14,000	)		(14,000	)

Net cash used in financing activities		(175,228	)		(141,400	)		(210,200	)

Net increase (decrease) in cash and cash equivalents		(11,695	)		(6,139	)		9,761

Cash and cash equivalents, beginning of period		15,267			21,406			11,645


Cash and cash equivalents, end of period	$	3,572		$	15,267		$	21,406


Supplemental disclosure of cash flow information
Interest paid (net of amounts capitalized)	$	72,439		$	72,067		$	74,714
Income tax paid	$	103,589		$	56,814		$	66,954

The accompanying notes are an integral part of these consolidated financial statements.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)		Corporate Structure

		Citrus Corp. (Citrus, the Company), a holding company formed in 1986, owns 100 percent of the membership interest in Florida Gas Transmission Company, LLC (Florida Gas), and 100 percent of the stock of Citrus Trading Corp. (Trading) and Citrus Energy Services, Inc. (CESI), collectively the Company. At December 31, 2007, the stock of Citrus was owned 50 percent by El Paso Citrus Holdings, Inc. (EPCH), a wholly-owned subsidiary of El Paso Corporation (El Paso), and 50 percent by CrossCountry Citrus, LLC (CCC), a wholly-owned subsidiary of CrossCountry Energy, LLC (CrossCountry). In November 2007, Southern Natural Gas Company (Southern), whose parent is El Paso, distributed EPCH to El Paso. CrossCountry was a wholly-owned subsidiary of Enron Corp. (Enron) and certain of its subsidiary companies. Effective November 17, 2004, CrossCountry became a wholly-owned subsidiary of CCE Holdings, LLC (CCE Holdings), which was a joint venture owned by subsidiaries of Southern Union Company (Southern Union) (50 percent), GE Commercial Finance Energy Financial Services (GE) (approximately 30 percent) and four minority interest owners (approximately 20 percent in the aggregate).

		On December 1, 2006, a series of transactions were completed which resulted in Southern Union increasing its indirect ownership interest in Citrus from 25 percent to 50 percent. On September 14, 2006, Energy Transfer Partners, L.P. (Energy Transfer), an unaffiliated company, entered into a definitive purchase agreement to acquire the 50 percent interest in CCE Holdings from GE and other investors. At the same time, Energy Transfer and CCE Holdings entered into a definitive redemption agreement, pursuant to which Energy Transfer’s 50 percent ownership interest in CCE Holdings would be redeemed in exchange for 100 percent of the equity interest in Transwestern Pipeline Company, LLC (TW) (Redemption Agreement). Upon closing of the Redemption Agreement on December 1, 2006, Southern Union became the indirect owner of 100 percent of CCE Holdings, whose principal remaining asset was its 50 percent interest in Citrus, with the remaining 50 percent of Citrus continuing to be owned by EPCH.

		Florida Gas, an interstate natural gas pipeline extending from South Texas to South Florida, is engaged in the interstate transmission of natural gas and is subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC).

		On September 1, 2006, Florida Gas converted its legal entity type from a corporation to a limited liability company, pursuant to the Delaware Limited Liability Company Act.

(2)		Significant Accounting Policies

		*Basis of Presentation* — The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).

		*Regulatory Accounting* — Florida Gas’ accounting policies generally conform to Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation (Statement No. 71). Accordingly, certain assets and liabilities that result from the regulated ratemaking process are recorded that would not be recorded under GAAP for non-regulated entities.

		Revenue Recognition — Revenues consist primarily of fees earned from gas transportation services. Reservation revenues are based on contracted rates and capacity reserved by the customers and are recognized monthly. For interruptible or volumetric based services, commodity revenues are recorded upon the delivery of natural gas to the agreed upon delivery point. Revenues for all services are generally based on the thermal quantity of gas delivered or subscribed at a rate specified in the contract.

		Because Florida Gas is subject to FERC regulations, revenues collected during the pendency of a rate proceeding may be required by the FERC to be refunded in the final order. Florida Gas establishes reserves for such potential refunds, as appropriate. There were no reserves for potential rate refund at December 31, 2007 and 2006, respectively.

		Derivative Instruments — The Company follows FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, (Statement No. 133) to account for derivative and hedging activities. In accordance with this statement, all derivatives are recognized on the Consolidated Balance Sheets

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

			at their fair value. On the date the derivative contract is entered into, the Company designates the derivative as (i) a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (a fair value hedge); (ii) a hedge of a forecasted transaction or the variability of cash flows to be received or paid in conjunction with a recognized asset or liability (a cash flow hedge); or (iii) an instrument that is held for trading or non-hedging purposes (a trading or non-hedging instrument). For derivatives treated as a fair value hedge, the effective portion of changes in fair value is recorded as an adjustment to the hedged item. The ineffective portion of a fair value hedge is recognized in earnings if the short cut method of assessing effectiveness is not used. Upon termination of a fair value hedge of a debt instrument, the resulting gain or loss is amortized to earnings through the maturity date of the debt instrument. For derivatives treated as a cash flow hedge, the effective portion of changes in fair value is recorded in Accumulated Other Comprehensive Loss until the related hedge items impact earnings. Any ineffective portion of a cash flow hedge is reported in current period earnings. For derivatives treated as trading or non-hedging instruments, changes in fair value are reported in current-period earnings. Fair value is determined based upon quoted market prices and mathematical models using current and historical data. As of December 31, 2007, the Company does not have any hedges in place as it is only amortizing previously terminated hedges.

			Property, Plant and Equipment — Property, Plant and Equipment consists primarily of natural gas pipeline and related facilities and is recorded at its original cost. Florida Gas capitalizes direct costs, such as labor and materials, and indirect costs, such as overhead and cost of funds, both interest and an equity return component (see third following paragraph). Costs of replacements and renewals of units of property are capitalized. The original cost of units of property retired are charged to accumulated depreciation, net of salvage and removal costs. Florida Gas charges to maintenance expense the costs of repairs and renewal of items determined to be less than units of property.

			The Company amortized that portion of its investment in Florida Gas property which is in excess of historical cost (acquisition adjustment) on a straight-line basis at an annual composite rate of 1.6 percent based upon the estimated remaining useful life of the pipeline system.

			Florida Gas has provided for depreciation of assets, on a straight-line basis, at an annual composite rate of 2.77 percent, 2.78 percent and 2.56 percent for the years ended December 31, 2007, 2006 and 2005, respectively.

			The recognition of an allowance for funds used during construction (AFUDC) is a utility accounting practice with calculations under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant. It represents the cost of capital invested in construction work-in-progress. AFUDC has been segregated into two component parts — borrowed funds and equity funds. The allowance for borrowed and equity funds used during construction, including related gross up, totaled $10.3 million, $3.4 million and $1.4 million for the years ended December 31, 2007, 2006 and 2005, respectively. AFUDC borrowed is included in Interest Expense and AFUDC equity is included in Other Income in the accompanying statements of income.

			Asset Retirement Obligations — The Company applies the provisions of FASB Statement No. 143, Accounting for Asset Retirement Obligations to record a liability for the estimated removal costs of assets where there is a legal obligation associated with removal. Under this standard, the liability is recorded at its fair value, with a corresponding asset that is depreciated over the remaining useful life of the long-lived asset to which the liability relates. An ongoing expense will also be recognized for changes in the value of the liability as a result of the passage of time.

			FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN No. 47) issued by the FASB in March 2005 clarifies that the term “conditional asset retirement obligation” as used in FASB Statement No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation (ARO) when incurred, if the fair value of the liability can be reasonably estimated. FIN No. 47 provides guidance for assessing whether sufficient information is available to record an estimate. This interpretation was effective for the Company beginning on December 31, 2005. Upon adoption of FIN No. 47, Florida Gas recorded an increase in plant in service and a liability for an ARO of $0.5 million. This new asset and liability related to obligations associated with the removal and disposal of asbestos and asbestos containing materials on Florida Gas’ pipeline system. The ARO asset at December 31, 2007 had a net book value of $0.5 million.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The table below provides a reconciliation of the carrying amount of the ARO liability for the period indicated:


	Year Ended December			Year Ended December			Year Ended December
	31, 2007			31, 2006			31, 2005
	(In thousands)
Beginning balance	$	481		$	493		$	—
Incurred		—			—			493
Settled		(37	)		(36	)		—
Accretion Expense		27			24			—

Ending balance	$	471		$	481		$	493

			Asset Impairment — The Company applies the provisions of FASB No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, to account for impairments on long-lived assets. Impairment losses are recognized for long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying value. The amount of impairment is measured by comparing the fair value of the asset to its carrying amount.

			Exchange Gas — Gas imbalances occur as a result of differences in volumes of gas received and delivered by a pipeline system. These imbalances due to or from shippers and operators are valued at an appropriate index price. Imbalances are settled in cash or made up in-kind subject to terms of Florida Gas’ tariff, and generally do not impact earnings.

			Environmental Expenditures (Note 12) — Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future generation, are expensed. Environmental expenditures relating to current or future revenues are expensed or capitalized as appropriate based on the nature of the cost incurred. Liabilities are recorded when environmental assessments and/or clean ups are probable and the cost can be reasonably estimated. Remediation obligations are not discounted because the timing of future cash flow streams is not predictable.

			Cash and Cash Equivalents — Cash equivalents consist of highly liquid investments with original maturities of three months or less. The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of these investments.

			Materials and Supplies — Materials and supplies are valued at the lower of cost or market value. Materials transferred out of warehouses are priced at average cost. Materials and supplies include spare parts which are critical to the pipeline system operations and are valued at the lower of cost or market.

			Fuel Tracker — A liability is recorded for net volumes of gas owed to customers collectively. Whenever fuel is due from customers from prior under recovery based on contractual and specific tariff provisions an asset is recorded. Gas owed to or from customers is valued at market. Changes in the balances have no effect on the consolidated income of the Company.

			Income Taxes (Note 4) — Income taxes are accounted for under the asset and liability method in accordance with the provisions of FASB Statement No. 109, Accounting for Income Taxes. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

			The determination of the Company’s provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items. Reserves are established when, despite management’s belief that the Company’s tax return positions are fully supportable, management believes that certain positions may be successfully challenged. When facts are circumstances change, these reserves are adjusted through the provision for income taxes.

			Accounts Receivable — The Company establishes an allowance for doubtful accounts on accounts receivable based on the expected ultimate recovery of these receivables. The Company considers many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors and transactions that might impact collectibility. Unrecovered accounts receivable charged against the allowance for doubtful accounts were $0.3 million, nil and nil in the years ended December 31, 2007, 2006 and 2005, respectively.

			Pensions and Postretirement Benefits — Effective December 31, 2006, the Company adopted the recognition and disclosure provisions of FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (Statement No. 158). Statement No. 158 requires employers to recognize in their balance sheets the overfunded or underfunded status of defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation. Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan in the year in which the change occurs through Accumulated Other Comprehensive Loss in stockholders’ equity. Effective for years beginning after December 15, 2008 (with early adoption permitted), Statement No. 158 also requires plan assets and benefit obligations to be measured as of the employers’ balance sheet date. The Company has not yet adopted the measurement provisions of Statement No. 158.

			Prior to adoption of the recognition provisions of Statement No. 158, the Company accounted for its defined benefit postretirement plans under FASB Statement No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions (Statement No. 106).” Statement No. 106 required that the liability recorded should represent the actuarial present value of all future benefits attributable to an employee’s service rendered to date. Under Statement No. 106, changes in the funded status were not immediately recognized; rather they were deferred and recognized ratably over future periods. Upon adoption of the recognition provisions of Statement No. 158, the Company recognized the amounts of these prior changes in the funded status of its postretirement benefit plans. The Company’s plan is in an overfunded position as of December 31, 2007. As the plan assets are derived through rates charged to customers, under Statement No. 71, to the extent the Company has collected amounts in excess of what is required to fund the plan, the Company has an obligation to refund the excess amounts to customers through rates. As such, the Company recorded the previously unrecognized changes in the funded status (i.e., actuarial gains) as a regulatory liability and not as an adjustment to Accumulated Other Comprehensive Loss.

			Use of Estimates — The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

			New Accounting Principles

			*Accounting Principles Not Yet Adopted.*

			*FIN 48,“ Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement 109” (FIN 48 or the Interpretation):* Issued by the FASB in June 2006, this Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition and measurement threshold attributable for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006, for public enterprises and December 15, 2007, for nonpublic enterprises,

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

			such as Citrus. The Company has determined the implementation of this Statement will not have a material impact on its consolidated financial statements.

			*FSP No. FIN 48-1, “Definition of ‘Settlement’ in FASB Interpretation No. 48” (FIN 48-1):* Issued by the FASB in May 2007, FIN 48-1 provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits.

			*FASB Statement No. 157, “Fair Value Measurements” (FASB Statement No. 157 or the Statement): Issued by the FASB in September 2006, this Statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. Where applicable, this Statement simplifies and codifies related guidance within GAAP. Except for certain non financial assets and liabilities more fully discussed in FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157” (FSP No. FAS 157-*2) which was issued by the FASB in February 2008, this Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. For those non financial assets and liabilities deferred pursuant to FSP No. FAS 157-2, this Statement is effective for financial statements for fiscal years beginning after November 15, 2008. The Company is currently evaluating the impact of this Statement on its consolidated financial statements.

			*FASB Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115”:* Issued by the FASB in February 2007, this Statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. The Statement does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value. The Statement is effective for fiscal years beginning after November 15, 2007. At January 1, 2008, the Company did not elect the fair value option under the Statement and, therefore, there was no impact to the Company’s consolidated financials statements.

			*FASB Statement No. 141 (revised), “Business Combinations”.*** Issued by the FASB in December 2007, this Statement changes the accounting for business combinations including the measurement of acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting for preacquisition gain and loss contingencies, the recognition of capitalized in-process research and development costs, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition related transaction costs and the recognition of changes in the acquirer’s income tax valuation allowance. The Statement is effective for fiscal years beginning after December 15, 2008, with early adoption prohibited.

			*FASB Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”***. Issued by the FASB in December 2007, this Statement changes the accounting for noncontrolling (minority) interests in consolidated financial statements including the requirements to classify noncontrolling interests as a component of consolidated stockholders’ equity, and the elimination of minority interest accounting in results of operations with earnings attributable to noncontrolling interests reported as part of consolidated earnings. Additionally, the Statement revises the accounting for both increases and decreases in a parent’s controlling ownership interest. The Statement is effective for fiscal years beginning after December 15, 2008, with early adoption prohibited. The Company is currently evaluating the impact of this statement on its consolidated financial statements.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(3)		Long Term Debt

		The table below sets forth the long-term debt of the Company as of the dates indicated:


	Years		December 31, 2007					December 31, 2006
	Due		Book Value			Fair Value		Book Value			Fair Value
	(In thousands)
Citrus
8.490% Senior Notes		2007-2009	$	60,000		$	63,572	$	90,000		$	95,011
Revolving Credit Agreement Citrus		2012		62,400			62,400		—			—
FGT
9.750% Senior B Notes		1999-2008		6,500			6,736		13,000			13,663
10.110% Senior C Notes		2009-2013		70,000			82,282		70,000			82,773
9.190% Senior Notes		2005-2024		127,500			158,843		135,000			167,004
7.625% Senior Notes		2010		325,000			353,352		325,000			348,137
7.000% Senior Notes		2012		250,000			277,281		250,000			271,893
Revolving Credit Agreement FGT		2007		—			—		40,000			40,000
Revolving Credit Agreement FGT		2012		54,000			54,000		—			—

Total debt outstanding			$	955,400		$	1,058,466	$	923,000		$	1,018,481

Current portion of long-term debt				(44,000	)				(84,000	)
Unamortized Debt Discount and Swap Loss				(1,590	)				(2,118	)

Total long-term debt			$	909,810				$	836,882

Annual maturities of long-term debt outstanding as of the date indicated were as follows:


	December 31,
	2007
Year	(In thousands)
2008	$	44,000
2009		51,500
2010		346,500
2011		21,500
2012		387,900
Thereafter		104,000

	$	955,400

On August 13, 2004 Florida Gas entered into a Revolving Credit Agreement (“2004 Revolver”) with an initial commitment level of $50 million, subsequently increased by $125 million to $175 million. Since that time, Florida Gas has routinely utilized the 2004 Revolver to fund working capital needs. On December 31, 2006, the amount drawn under the 2004 Revolver was $40 million, with a weighted average interest rate of 6.08 percent (based on LIBOR plus 0.70 percent). Additionally, a commitment fee of 0.15 percent is payable quarterly on the unused portion of the commitment balance. The 2004 Florida Gas Revolver terminated in August 2007 and was replaced by a new revolving credit agreement at Florida Gas in the amount of $300 million (“2007 Florida Gas Revolver”), which will mature on August 16, 2012. The 2007 Florida Gas Revolver

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		requires interest based on LIBOR plus a margin tied to the debt rating of the Company’s senior unsecured debt, currently 0.28 percent, and has a facility fee of 0.07 percent. As of December 31, 2007, the amount drawn under the 2007 Florida Gas Revolver was $54 million with a weighted average interest rate of 5.30 percent (based on LIBOR plus 0.28 percent).

		Also on August 16, 2007, Citrus entered into a revolving credit facility in the amount of $200 million (“2007 Citrus Revolver”), which will mature on August 16, 2012. This facility will enable Citrus to meet its funding needs and repay its debt maturities. As of December 31, 2007, the amount drawn under the 2007 Citrus Revolver was $62.4 million with a weighted average interest rate of 5.22 percent (based on LIBOR plus 0.28 percent), and has a facility fee of 0.07 percent. Issuance costs for the 2007 Florida Gas Revolver and 2007 Citrus Revolver were $0.3 million and $0.2 million, respectively at December 31, 2007.

		The book value of the 2004 Revolver, 2007 Florida Gas Revolver, and 2007 Citrus Revolver approximates their market value given the variable rate of interest. Estimated fair value amounts of other long-term debt were obtained from independent parties, and are based upon market quotations of similar debt at interest rates currently available. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 2007 and 2006 are not necessarily indicative of the amounts the Company could have realized in current market exchanges.

		The agreements relating to Florida Gas’ debt include, among other things, restrictions as to the payment of dividends and maintaining certain restrictive financial covenants, including a required ratio of consolidated funded debt to total capitalization.

		Under the terms of its debt agreements, Florida Gas may incur additional debt to refinance maturing obligations if the refinancing does not increase aggregate indebtedness, and thereafter, if Citrus’ and Florida Gas’ consolidated debt does not exceed specific debt to total capitalization ratios, as defined in certain debt instruments. Incurrence of additional indebtedness to refinance the current maturities would not result in a debt to capitalization ratio exceeding these limits.

		All of the debt obligations of Citrus and Florida Gas have events of default that contain commonly used cross-default provisions. An event of default by either Citrus or Florida Gas on any of their borrowed money obligations, in excess of certain thresholds which is not cured within defined grace periods, would cause the other debt obligations of Citrus and Florida Gas to be accelerated.

(4)		Income Taxes

		The principal components of the Company’s net deferred income tax liabilities as of the dates indicated were as follows:


	December 31,		December 31,
	2007		2006
	(In thousands)
Deferred income tax asset
Regulatory and other reserves	$	5,554	$	8,595

		5,554		8,595


Deferred income tax liabilities
Depreciation and amortization		759,576		742,566
Deferred charges and other assets		—		27,981
Regulatory costs		4,717		9,298
Other		4,625		6,154

		768,918		785,999

Net deferred income tax liabilities	$	763,364	$	777,404

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Total income tax expense for the periods indicated was as follows:


	Year Ended			Year Ended		Year Ended
	December 31,			December 31,		December 31,
	2007			2006		2005
	(In thousands)
Current Tax Provision
Federal	$	99,083		$	52,135	$	53,526
State		5,418			5,196		8,820

		104,501			57,331		62,346


Deferred Tax Provision
Federal		(14,531	)		15,863		11,079
State		2,254			2,766		1,661

		(12,277	)		18,629		12,740

Total income tax expense	$	92,224		$	75,960	$	75,086

The differences between taxes computed at the U.S. federal statutory rate of 35 percent and the Company’s effective tax rate for the periods indicated are as follows:


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2007			2006			2005
	(In Thousands)

Statutory federal income tax provision	$	87,261		$	70,712		$	69,661
State income taxes, net of federal benefit		4,986			5,176			6,813
Other		(23	)		72			(1,388	)

Income tax expense	$	92,224		$	75,960		$	75,086


Effective Tax Rate		37.0	%		37.6	%		37.7	%

		The Company files a consolidated federal income tax return separate from that of its stockholders.

(5)		Employee Benefit Plans

		The employees of the Company were covered under Enron’s employee benefit plans until November 2004.

		Enron maintained a pension plan that was a noncontributory defined benefit plan, the Enron Corp. Cash Balance Plan (the Cash Balance Plan), covering certain Enron employees in the United States and certain employees in foreign countries. The basic benefit accrual was 5 percent of eligible annual base pay. In 2003 the Company recognized its portion of the expected Cash Balance Plan settlement by recording a $9.6 million current liability, which was cash settled in 2005 (Note 7), and a charge to operating expense. In 2004, with the settlement of the rate case (Note 8), Florida Gas recognized a regulatory asset for its portion, $9.3 million, with a reduction to operating expense. Per the rate case settlement Florida Gas will amortize, over five years retroactive to April 1, 2004, its allocated share of costs to fully fund and terminate the Cash Balance Plan. Amortization recorded was $1.9 million, $1.8 million and $1.9 million for the years ended December 31, 2007,

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2006 and 2005, respectively. At December 31, 2007 and 2006 the remaining regulatory asset balance was $2.3 million and $4.2 million, respectively (Note 10).

Effective November 1, 2004 all employees of the Company were transferred to an affiliated entity, CrossCountry Energy Services, LLC (CCES) and during November 2004, employee insurance coverage migrated (without lapse) from Enron plans to new CCES welfare and benefit plans. Effective March 1, 2005 essentially all such employees were transferred to Florida Gas and became eligible at that time to participate in employee welfare and benefit plans adopted by Florida Gas.

Effective March 1, 2005 Florida Gas adopted the Florida Gas Transmission Company 401(k) Savings Plan (the Plan). All employees of Florida Gas are eligible to participate and, within one Plan, may contribute up to 50 percent of pre-tax compensation, subject to IRS limitations. This Plan allows additional “catch-up” contributions by participants over age 50, and allows Florida Gas to make discretionary profit sharing contributions for the benefit of all participants. Florida Gas matched 50 percent of participant contributions under this Plan up to a maximum of four percent of eligible compensation through December 31, 2007. The matching was increased effective January 1, 2008 to 100 percent of the first two percent and 50 percent of the next three percent of the participant’s compensation paid into the Plan. Participants vest in such matching and any profit sharing contributions at the rate of 20 percent per year, except that participants with five years of service at the date of adoption of the Plan were immediately vested. Administrative costs of the Plan and certain asset management fees are paid from Plan assets. Florida Gas’ expensed its contribution of $0.3 million, $0.4 million, and $0.3 million for the years ended December 31, 2007, 2006, and 2005 respectively.

Other Post — Employment Benefits

Prior to December 1, 2004 Florida Gas was a participating employer in the Enron Gas Pipelines Employee Benefit Trust (the Trust), a voluntary employees’ beneficiary association (VEBA) under Section 501(c)(9) of the Internal Revenue Code of 1986, as amended (Tax Code), which provided certain post-retirement medical, life insurance and dental benefits to employees of Florida Gas and certain other Enron affiliates pursuant to the Enron Corp. Medical Plan and the Enron Corp. Medical Plan for Inactive Participants. Enron has made the determination that it will partition the Trust and distribute the assets and liabilities of the Trust among the participating employers of the Trust on a pro rata basis according to the contributions and liabilities associated with each participating employer. The Trust Committee has final approval on allocation methodology for the Trust assets. It is estimated that Florida Gas will receive approximately $6.8 million from the Trust, including an estimated investment return as early as first quarter 2008. Enron filed a motion in the Enron bankruptcy proceedings on July 22, 2003 which was stayed and then refiled and amended on June 17, 2005 and again refiled and amended on December 1, 2006 which provides that each participating employer expressly assumes liability for its allocable portion of retiree benefits and releases Enron from any liability with respect to the Trust in order to receive the assets of the Trust. On June 7, 2005 a class action suit captioned Lou Geiler et al v. Robert W. Jones, et al., was filed in United States District Court for the District of Nebraska by, among others, former employees of Northern Natural Gas Company (Northern) on behalf of the participants in the Northern Medical and Dental Plan for Retirees and Surviving Spouses against former and present members of the Trust Committee, the Trustee and the participating employers of the Trust, including Florida Gas, claiming the Trust Committee and the Trustee have violated their fiduciary duties under ERISA and seeking a declaration from the Court binding on all participating employers of an accounting and distribution of the assets held in the Trust and a complete and accurate listing of the individuals properly allocated to Northern from the Enron Plan. On the same date essentially the same group filed a motion in the Enron bankruptcy proceedings to strike the Enron motion from further consideration. On February 6, 2006 the Nebraska action was dismissed. The plaintiffs filed an appeal of the dismissal on March 8, 2006. An agreement was reached on the conditions of the partition of the Trust among the VEBA participating employers, Enron and the Trust Committee and approved by the Enron bankruptcy court on December 21, 2006. As a result, the Nebraska action appeal was dismissed on January 25, 2007.

During the period December 1, 2004 through February 28, 2005, following Florida Gas’ November 17, 2004 acquisition by CCE Holdings, coverage to eligible employees and their eligible dependents was provided by CrossCountry Energy Retiree Health Plan, which provides only medical benefits. Florida Gas continues to provide certain retiree benefits through employer contributions to a qualified contribution plan, with the amounts generally varying based on age and years of service.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Effective March 1, 2005 such benefits are provided under an identical plan sponsored by Florida Gas as a single employer post-retirement benefit plan.

With regard to its sponsored plan, Florida Gas has entered into a VEBA trust (the “VEBA Trust”) agreement with JPMorgan Chase Bank Trust Company as trustee. The VEBA Trust has established or adopted plans to provide certain post-retirement life, health, accident and other benefits. The VEBA Trust is a voluntary employees’ beneficiary association under Section 501(c)(9) of the Tax Code, which provides benefits to employees of the Company. Florida Gas contributed $0.5 million and $1.2 million to the VEBA Trust for the years ended December 31, 2007 and 2006, respectively. Upon settlement of the Trust, the anticipated distribution of assets to Florida Gas from the Trust will be contributed to the VEBA Trust.

Prior to 2005, Florida Gas’ general policy was to fund accrued post-retirement health care costs as allocated by Enron. As a result of Florida Gas’ change in 2005 from a participant in a multi employer plan to a single employer plan, Florida Gas now accounts for its OPEB liability and expense on an actuarial basis, recording its health and life benefit costs over the active service period of employees to the date of full eligibility for the benefits. At December 31, 2005 Florida Gas recognized its OPEB liability by recording a deferred credit of $2.2 million and a corresponding regulatory asset of $2.2 million.

The Company has postretirement health care plans which cover substantially all employees. The health care plans generally provide for cost sharing in the form of retiree contributions, deductibles, and coinsurance between the Company and its retirees, and a fixed cost cap on the amount the Company pays annually to provide future retiree health care coverage under certain of these plans.

The following table summarizes the impact of adopting Statement No. 158 on the Company’s postretirement plan reported in the Consolidated Balance Sheet at December 31, 2006:


				FASB 158
				adoption
	Pre-FASB 158			adjustment			Post-FASB 158
				(In Thousands)

Prepaid postretirement benefit cost (non-current) (Note 10)	$	(721	)	$	3,423		$	2,702
Regulatory asset		1,951			(1,951	)		—
Regulatory liability		—			(1,472	)		(1,472	)

The adoption of Statement No. 158 had no effect on the Consolidated Statements of Income for the years ended December 31, 2007 and December 31, 2006, or for any prior period presented, has not negatively impacted any financial covenants, and is not expected to affect the Company’s operating results in future periods.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table represents a reconciliation of Florida Gas’ OPEB plan for the periods indicated:


	Year Ended			Year Ended
	December 31,			December 31,
	2007			2006
	(In thousands)
Change in Benefit Obligation
Benefit obligation at the beginning of period	$	5,795		$	6,665
Service cost		37			46
Interest cost		296			312
Actuarial gain		(320	)		(691	)
Retiree premiums		415			427
Benefits paid		(1,029	)		(964	)
CMS Medicare Part D Subsidies Received		108			—

Benefit obligation at end of year		5,302			5,795


Change in Plan Assets
Fair value of plan assets at the beginning of period		8,497			7,840
Return on plan assets		336			(37	)
Employer contributions		380			1,231
Retiree premiums		415			427
Benefits paid		(1,029	)		(964	)

Fair value of plan assets at end of year (1)		8,599			8,497


Funded Status Funded status at the end of the year	$	3,297		$	2,702


Amount recognized in the Consolidated Balance Sheets
Other assets — other (Note 10)	$	3,297		$	2,702
Regulatory liability (Note 11)		(3,390	)		(1,472	)

Net asset (liability) recognized	$	(93	)	$	1,230


(1)		Plan assets at December 31, 2007 and 2006 include the amounts of assets expected to be received from the Enron Trust of $6.8 million and $6.5 million, respectively, including a 5 percent annual investment return based on estimate.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The weighted-average assumptions used to determine Florida Gas’ benefit obligations for the periods indicated were as follows:


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2007			2006			2005

Discount rate		6.09	%		5.68	%		5.50	%
Health care cost trend rates		10.00	%		11.00	%		12.00	%
	graded to 5.20%			graded to 4.85%			graded to 4.65%
	by 2017			by 2013			by 2012

Florida Gas’ net periodic (benefit) costs for the periods indicated consisted of the following:


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2007			2006			2005
	(In thousands)

Service cost	$	37		$	46		$	71
Interest cost		296			312			490
Expected return on plan assets		(414	)		(402	)		(352	)
Recognized actuarial gain		(230	)		(223	)		(174	)

Net periodic (benefit) cost	$	(311	)	$	(267	)	$	35

The weighted-average assumptions used to determine Florida Gas’ net periodic benefit costs for the periods indicated were as follows:


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2007			2006			2005

Discount rate		5.68	%		5.50	%		5.75	%
Rate of compensation increase		N/A			N/A			N/A
Expected long-term return on plan assets		5.00	%		5.00	%		5.00	%
Health care cost trend rates		11.00	%		12.00	%		12.00	%
	graded to 4.85%			graded to 4.65%			graded to 4.75%
	by 2013			by 2012			by 2012

Florida Gas employs a building block approach in determining the expected long-term rate on return on plan assets. Historical markets are studied and long-term historical relationships between equities and fixed-income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. The long-term portfolio return is

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

established via a building block approach with proper consideration of diversification and rebalancing. Peer data and historical returns are reviewed to check for reasonability and appropriateness.

Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:


	One Percentage		One Percentage
	Point Increase		Point Decrease
	(In thousands)
Effect on total service and interest cost components	$	15	$	(13	)
Effect on postretirement benefit obligation	$	240	$	(215	)

Discount Rate Selection — The discount rate for each measurement date has been determined consistent with the discount rate selection guidance in Statement No. 106 (as amended by Statement No. 158) using the Citigroup Pension Discount Curve as published on the Society of Actuaries website as the hypothetical portfolio of high-quality debt instruments that would provide the necessary cash flows to pay the benefits when due.

Plan Asset Information — The plan assets shall be invested in accordance with sound investment practices that emphasize long-term investment fundamentals. An investment objective of income and growth for the plan has been adopted. This investment objective: (i) is a risk-averse balanced approach that emphasizes a stable and substantial source of current income and some capital appreciation over the long-term; (ii) implies a willingness to risk some declines in value over the short-term, so long as the plan is positioned to generate current income and exhibits some capital appreciation; (iii) is expected to earn long-term returns sufficient to keep pace with the rate of inflation over most market cycles (net of spending and investment and administrative expenses), but may lag inflation in some environments; (iv) diversifies the plan in order to provide opportunities for long-term growth and to reduce the potential for large losses that could occur from holding concentrated positions; and (iv) recognizes that investment results over the long-term may lag those of a typical balanced portfolio since a typical balanced portfolio tends to be more aggressively invested. Nevertheless, this plan is expected to earn a long-term return that compares favorably to appropriate market indices.

It is expected that these objectives can be obtained through a well-diversified portfolio structure in a manner consistent with the investment policy.

Florida Gas’ OPEB weighted-average asset allocation by asset category for the $1.8 million and $2.0 million of assets actually in the VEBA Trust at December 31, 2007 and 2006, respectively, were approximately as follows:


	December 31,			December 31,
	2007			2006
Equity securities		31	%		0	%
Debt securities		69	%		0	%
Cash and cash equivalents		0	%		100	%

Total		100	%		100	%

Based on the postretirement plan objectives, asset allocations should be maintained as follows: equity of 25 percent to 35 percent, fixed income of 65 percent to 75 percent, and cash and cash equivalents of 0 percent to 10 percent.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The above referenced asset allocations for postretirement benefits are based upon guidelines established by Florida Gas’ Investment Policy and is monitored by the Investment Committee of the board of directors in conjunction with an external investment advisor.

Florida Gas expects to contribute approximately $1.1 million to its post-retirement benefit plan in 2008 and approximately $1.1 million annually thereafter until modified by rate case proceedings.

The estimated employer portion of benefit payments, which reflect expected future service, as appropriate, that are projected to be paid are as follows:


	Expected Benefits
	Before Effect of		Payments Medicare
Years	Medicare Part D		Part D		Net
	(In thousands)
2008	$	551	$	96	$	455
2009		594		99		495
2010		614		101		513
2011		625		101		524
2012		624		100		524
2013 — 2017		2,935		454		2,481

		The Medicare Prescription Drug Act was signed into law December 8, 2003. The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy, which is not taxable, to sponsors of retiree healthcare benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

(6)		Major Customers and Concentration of Credit Risk

		Revenues from individual third party and affiliate customers exceeding 10 percent of total revenues for the periods indicated were approximately as listed below, and in total represented 56%, 58% and 54% of total revenue, respectively.


	Year Ended December		Year Ended December		Year Ended December
	31, 2007		31, 2006		31, 2005
	(In thousands)
Florida Power & Light Company	$	195,622	$	200,592	$	181,486
TECO Energy, Inc.		80,815		80,192		76,059

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company had the following transportation receivables from these customers at the dates indicated:


	December 31, 2007		December 31, 2006
	(In thousands)

Florida Power & Light Company	$	15,130	$	15,065
TECO Energy, Inc.		6,201		6,161

		The Company has a concentration of customers in the electric and gas utility industries. These concentrations of customers may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. Credit losses incurred on receivables in these industries compare favorably to losses experienced in the Company’s receivable portfolio as a whole. The Company also has a concentration of customers located in the southeastern United States, primarily within the state of Florida. Receivables are generally not collateralized. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments, deposits, or other forms of security to the Company. Florida Gas sought additional assurances from customers due to credit concerns, and had customer deposits totaling $1.6 million and $1.6 million, and prepayments of $43,000 and $0.2 million at December 31, 2007 and 2006, respectively. The Company’s management believes that the portfolio of Florida Gas’ receivables, which includes regulated electric utilities, regulated local distribution companies, and municipalities, is of minimal credit risk.

(7)		Related Party Transactions

		In December 2001 Enron and certain of its subsidiaries filed voluntary petitions for Chapter 11 reorganization with the U.S. Bankruptcy court. At December 31, 2004 Florida Gas and Trading had aggregate outstanding claims with the Bankruptcy Court against Enron and affiliated bankrupt companies of $220.6 million. Of these claims, Florida Gas and Trading filed claims totaling $68.1 and $152.5 million, respectively. Florida Gas and Trading claims pertaining to contracts rejected by ENA were $21.4 and $152.3 million, respectively. In March 2005, ENA filed objections to Trading’s claim. In September 2006 the judge issued an order rejecting certain of Trading’s arguments and ruling that a contract under which ENA had an in the money position against Trading may be offset against a related contract under which Trading had an in the money position against ENA. The result of the order was a reduction in the allowable amount of Trading’s initial claim to $22.7 million. The parties reached a settlement which was approved by the Bankruptcy Court in March 2007 (See Note 14).

		Florida Gas’ claims against ENA on transportation contracts were reduced by approximately $21.2 million when a third party took assignment of ENA’s transportation contracts. In 2004 Florida Gas settled the amount of all of its claims against Enron and a subsidiary debtor. Total allowed claims (including debtor set-offs) were $13.3 million. After approval of the settlement by the Bankruptcy Court, in June 2005 Florida Gas sold its claims, received $3.4 million and recorded Other Income of $0.9 million.

		Florida Gas had a construction reimbursement agreement with ENA under which amounts owed to Florida Gas were delinquent. These obligations totaled approximately $7.4 million and were included in Florida Gas’ filed bankruptcy claims. These receivables were fully reserved by Florida Gas prior to 2003. Under the Settlement filed by Florida Gas on August 13, 2004 and approved by the FERC on December 21, 2004 Florida Gas will recover the under-recovery on this obligation by rolling in the costs of the facilities constructed, less the recovery from ENA, in its tariff rates (see Note 8). As part of the June 2005 sale of its claims, Florida Gas received $2.1 million for this part of the claim.

		The Company provided natural gas sales and transportation services to El Paso affiliates at rates equal to rates charged to non-affiliated customers in the same class of service. Revenues related to these transportation services were approximately nil, $1.0 million and $4.5 million in the years ended December 31, 2007, 2006 and 2005, respectively. The Company’s gas sales were immaterial in the years ended December 31, 2007, 2006

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		and 2005. Florida Gas also purchased transportation services from Southern in connection with its Phase III Expansion completed in early 1995. Florida Gas contracted for firm capacity of 100,000 Mcf/day on Southern’s system for a primary term of 10 years, to be continued for successive terms of one year each year thereafter unless cancelled by either party, by giving 180 days notice to the other party prior to the end of the primary term or any yearly extension thereof. The amount expensed for these services totaled $6.8 million, $6.6 million and $6.3 million in the years ended December 31, 2007, 2006 and 2005, respectively.

		Effective April 1, 2004 services previously provided by bankrupt Enron affiliates to the Company pursuant to the allocation methodology ordered by the Bankruptcy Court were covered and charged under the terms of the Transition Services Agreement / Transition Supplemental Services Agreement (TSA/TSSA). This agreement between Enron and CrossCountry was administered by CrossCountry Energy Services, LLC (CCES), a subsidiary of CCE Holdings, which allocated to the Company its share of total costs. Effective November 17, 2004 an Amended TSA/TSSA agreement was put into effect. This agreement expired on July 31, 2005. The total costs are not materially different from those previously charged. The amount expensed for the seven month-period ended July 31, 2005 was approximately $1.5 million.

		On November 5, 2004, CCE Holdings entered into an Administrative Services Agreement (ASA) with SU Pipeline Management LP (Manager), a Delaware limited partnership and a wholly-owned subsidiary of Southern Union. Pursuant to the ASA, Manager was responsible for the operations and administrative functions of the enterprise, CCE Holdings and Manager shared certain operations of Manager and its affiliates, and CCE Holdings was obligated to bear its share of costs of Manager and its affiliates. Costs are allocated by Manager and its affiliates to the operating subsidiaries and investees, based on relevant criteria, including time spent, miles of pipe, total assets, labor allocations, or other appropriate methods. Manager provided services to CCE Holdings from November 17, 2004 to December 1, 2006. Following the closing of the Redemption Agreement on December 1, 2006, services continue to be provided by Southern Union affiliates to Florida Gas, and costs allocated using allocation methods consistent with past practices.

		The Company has related party activities for operational and administrative services performed by CCES, Panhandle Eastern Pipe Line Company, LP (PEPL), an indirect wholly-owned subsidiary of Southern Union, and other related parties, on behalf of the Company, and corporate service charges from Southern Union. Expenses are generally charged based on either actual usage of services or allocated based on estimates of time spent working for the benefit of the various affiliated companies. Amounts expensed by the Company were $21.5 million, $20.6 million and $20.2 million in the years ended December 31, 2007, 2006 and 2005, respectively, and included corporate service charges from Southern Union of $5.9 million, $4.0 million and $1.6 million in the years ended December 31, 2007, 2006 and 2005, respectively. Additionally, the Company receives allocated costs of certain shared business applications from PEPL and Southern Union. At December 31, 2007 and 2006, the Company had current accounts payable to affiliated companies of $8.4 million and $2.8 million, respectively, relating to these services.

		In 2005, the Company paid a subsidiary of CCE Holdings $9.6 million to settle the Cash Balance Plan obligation, which CCE Holdings effectively paid in conjunction with the 2004 acquisition of the Company.

		The Company paid cash dividends to its shareholders of $207.1 million, $125.4 million and $121.2 million in the years ended December 31, 2007, 2006, and 2005, respectively. The Company also declared a dividend in December 2007 of $42.6 million, payable in January, 2008 and which was paid on January 18, 2008.

(8)		Regulatory Matters

		On August 13, 2004 Florida Gas filed a Stipulation and Agreement of Settlement (“Rate Case Settlement”) in its Section 4 rate proceeding in Docket No. RP04-12, which established settlement rates and resolved all issues. The settlement rates were approved and became effective on April 1, 2004 for all Florida Gas services and again on April 1, 2005 for Rate Schedule FTS-2 when the basis for rates on Florida Gas incremental facilities changed from a levelized cost of service to a traditional cost of service.

		On December 15, 2003 the U.S. Department of Transportation issued a Final Rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the regulation defines as “high consequence areas”

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		(“HCA”). This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The rule requires operators to identify HCAs along their pipelines by December 2004 and to have begun baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing, or direct assessment, by June 2004. Operators were required to rank the risk of their pipeline segments containing HCAs and to complete assessments on at least 50 percent of the segments using one or more of these methods by December 2007. Assessments will generally be conducted on the higher risk segments first with the balance being completed by December 2012. As of December 31, 2007, Florida Gas completed 62 percent of the risk assessments. In addition, some system modifications will be necessary to accommodate the in-line inspections. All systems operated by the Company will be compliant with the rule; however, while identification and location of all the HCAs has been completed, it is impossible to determine with certainty the total scope of required remediation activities prior to completion of the assessments and inspections. The required modifications and inspections are currently estimated to be in the range of approximately $21 million to $28 million per year through 2012. Pursuant to the August 13, 2004 Rate Case Settlement, Florida Gas has the right to make limited sections 4 filings to recover, via a surcharge during the settlement’s term, depreciation and return on up to approximately $40 million of such costs, as well as security, and Florida Turnpike relocation and modification costs. A reservation surcharge of $0.02 per MMBtu has been in effect since April 1, 2007, subject to refund and further review by the FERC.

		In June 2005 FERC issued an order Docket No. AI05-1-000 that expands on the accounting guidance in the proposed accounting release issued in November 2004 on mandated pipeline integrity programs. The order interprets the FERC’s existing accounting rules and standardizes classifications of expenditures made by pipelines in connection with an integrity management program. The order is effective for integrity management expenditures incurred on or after January 1, 2006. Florida Gas capitalizes all pipeline assessment costs pursuant to its August 13, 2004 Rate Case Settlement. The Rate Case Settlement contained no reference to the FERC Docket No. AI05-1-000 regarding pipeline assessment costs and provided that the final FERC order approving the Rate Case Settlement constituted final approval of all necessary authorizations to effectuate its provisions. The Rate Case Settlement provisions became effective on March 1, 2005 and new tariff sheets to implement these provisions were filed on March 15, 2005. FERC issued an order accepting the tariff sheets on May 20, 2005. In the years ended December 31, 2007 and 2006, Florida Gas completed and capitalized $9.5 million and $6.7 million, respectively on pipeline assessment projects, as part of the integrity programs.

		On October 5, 2005 Florida Gas filed an application with FERC for the Company’s proposed Phase VII expansion project. The project will expand Florida Gas’ existing pipeline infrastructure in Florida and provide the growing Florida energy market access to additional natural gas supply from the Southern LNG Elba Island liquefied natural gas import terminal near Savannah, Georgia. The Phase VII project calls for Florida Gas to build approximately 17 miles of 36-inch diameter pipeline looping in several segments along an existing right of way and install 9,800 horsepower of compression in a first phase with the possibility of a future second phase. The expansion as currently planned will provide about 100 million cubic feet per day (MMcf/d) of additional capacity to transport natural gas from a connection with Southern Natural Gas Company’s Cypress Pipeline project in Clay County, Florida. The FERC issued an order approving the project on June 15, 2006 and construction commenced on November 6, 2006. The first phase was partially placed in service in May 2007 while certain modifications at compressor station 26 are expected to be in service by the end of March, 2008. The updated estimated cost of the expansion is approximately $62 million, including AFUDC. Approximately $12.6 million and $39.3 million is recorded in the line item Construction work in progress at December 31, 2007 and December 31, 2006, respectively.

		On October 20, 2005, Florida Gas filed an application with FERC for the Company’s State Road 91 Relocation Project. The proposed project will consist of the abandonment of approximately 11.15 miles of 18-inch diameter pipeline and 10.75 miles of 24-inch diameter pipeline in Broward, County Florida. The replacement pipeline will consist of approximately 11.15 miles of 36-inch diameter pipeline. The abandonment and replacement is being performed to accommodate the widening of State Road 91 by the Florida Department of Transportation/Florida Turnpike Enterprise (FDOT/FTE). The estimated cost of the pipeline relocation project is estimated at $110 million, including AFUDC, and Florida Gas is seeking recovery of the construction costs from the FDOT/FTE. The FERC issued an order approving the project on May 3, 2006. Florida Gas notified the FERC that construction commenced on April 25, 2007.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		Florida Gas plans to seek FERC approval to construct an expansion to increase its natural gas capacity into Florida by approximately 800 MMcf/d (Phase VIII Expansion). The Phase VIII Expansion includes construction of approximately 500 miles of additional large diameter pipeline and the installation of approximately 170,000 horsepower of additional compression. Pending FERC approval, which is expected in 2009, Florida Gas anticipates an in-service date of 2011, at an approximate cost of $2 billion. Florida Gas has signed a 25-year agreement with Florida Power and Light Company, (FPL), a wholly-owned subsidiary of FPL Group, Inc., for 400 MMcf/d of capacity.

(9)		Property, Plant and Equipment

		The principal components of the Company’s property, plant and equipment at the dates indicated were as follows:


	December 31,			December 31,
	2007			2006
	(In thousands)
Transmission plant	$	2,970,560		$	2,859,920
General plant		28,540			24,970
Intangibles		31,196			25,726
Construction work-in-progress		133,824			85,746
Acquisition adjustment		1,252,466			1,252,466

		4,416,586			4,248,828
Less: Accumulated depreciation and amortization		(1,401,638	)		(1,304,133	)

Property, Plant and Equipment, net	$	3,014,948		$	2,944,695

(10)		Other Assets

		The principal components of the Company’s regulatory assets at the dates indicated were as follows:


	December 31,		December 31,
	2007		2006
	(In thousands)
Ramp-up assets, net (1)	$	11,616	$	11,928
Fuel Tracker		2,295		11,747
Cash balance plan settlement (Note 5)		2,326		4,185
Environmental non-PCB clean-up cost (Note 12)		1,147		1,000
Other miscellaneous		1,823		2,147

Total Regulatory Assets	$	19,207	$	31,007


(1)		Ramp-up assets are regulatory assets which Florida Gas was specifically allowed to establish in the FERC certificates authorizing the Phase IV and V Expansion projects.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The principal components of the Company’s other assets at the dates indicated were as follows:


	December 31,		December 31,
	2007		2006
	(In thousands)
Long-term receivables (Note 14)	$	2,859	$	71,648
Other post employment benefits (Note 5)		3,297		2,702
Preliminary survey & investigation		3,021		996
FERC ACA fee		1,061		839
Other miscellaneous		600		244

Total Other Assets — other	$	10,838	$	76,429

(11)		Deferred Credits

		The principal components of the Company’s regulatory liabilities at the dates indicated were as follows:


	December 31,		December 31,
	2007		2006
	(In thousands)
Balancing tools (1)	$	11,413	$	12,154
Other post employment benefits (Note 5)		3,390		1,472
Other miscellaneous		39		630

Total Regulatory liabilities	$	14,842	$	14,256


(1)		Balancing tools are a regulatory method by which Florida Gas recovers the costs of operational balancing of the pipeline’s system. The balance can be a deferred charge or credit, depending on timing, rate changes and operational activities.

The principal components of the Company’s other deferred credits at the dates indicated were as follows:


	December 31,		December 31,
	2007		2006
	(In thousands)
Post construction mitigation costs	$	1,686	$	2,073
Deferred compensation		889		1,090
Environmental non-PCB clean-up cost reserve (Note 12)		1,337		1,423
Taxes Payable		3,116		1,664
Asset retirement obligation (Note 2)		471		481
Other miscellaneous		1,703		1,398

Total Deferred Credits — other	$	9,202	$	8,129

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(12)		Environmental Reserve

		The Company is subject to extensive federal, state and local environmental laws and regulations. These laws and regulations require expenditures in connection with the construction of new facilities, the operation of existing facilities and for remediation at various operating sites. The implementation of the Clean Air Act Amendments resulted in increased operating expenses. These increased operating expenses did not have a material impact on the Company’s consolidated financial statements.

		Florida Gas conducts assessment, remediation, and ongoing monitoring of soil and groundwater impact which resulted from its past waste management practices at its Rio Paisano and Station 11 facilities. The anticipated costs over the next five years are: 2008 — $0.3 million, 2009 - $0.1 million, 2010 — $0.2 million, 2011 — $0.3 million and 2012 — $0.1 million. The expenditures thereafter are estimated to be $0.6 million for soil and groundwater remediation. The liability is recognized in other current liabilities and in other deferred credits and in total amounted to $1.6 million and $1.6 million at December 31, 2007 and 2006, respectively. Costs of $0.2 million, $0.1 million and $0.8 million were expensed during the years ended December 31, 2007, 2006 and 2005, respectively. Florida Gas recorded the estimated costs of remediation to be spent after April 1, 2010 of $1.1 million and $1.0 million at December 31, 2007 and 2006, respectively (Note 10), as a regulatory asset based on the probability of recovery in rates in its next rate case.

		Prior to December 31, 2005, no such liability was recognized since it was previously estimated to be less than $1.0 million, and therefore, considered not to be material. Amounts incurred for environmental assessment and remediation were expensed as incurred.

(13)		Accumulated Other Comprehensive Loss

		Deferred gains and losses in connection with the termination of the following derivative instruments which were previously accounted for as cash flow hedges form part of other comprehensive income. Such amounts are being amortized over the terms of the hedged debt.

		The table below provides an overview of comprehensive income for the periods indicated:


	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2007			2006			2005
	(In thousands)
Interest rate swap loss on 7.625%$325 million note due 2010	$	1,873		$	1,872		$	1,872
Interest rate swap loss on 7.0%$250 million note due 2012		1,228			1,228			1,228
Interest rate swap gain on 9.19%$150 million note due 2005-2024		(462	)		(462	)		(462	)

Total	$	2,639		$	2,638		$	2,638

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The table below provides an overview of the components in accumulated other comprehensive loss at the dates indicated:


	Termination	Amortization	Original			December 31,			December 31,
	Date	Period	Gain/(Loss)			2007			2006
						(In thousands)
Interest rate swap loss on 7.625% $325 million note due 2010	December 2000	10 years	$	(18,724	)	$	(5,461	)	$	(7,334	)
Interest rate swap loss on 7.0% $250 million note due 2012	July 2002	10 years		(12,280	)		(5,579	)		(6,807	)
Interest rate swap gain on 9.19% $150 million note due 2005-2024	November 1994	20 years		9,236			3,155			3,617

Total						$	(7,885	)	$	(10,524	)

(14)		Commitments and Contingencies

		From time to time, in the normal course of business, the Company is involved in litigation, claims or assessments that may result in future economic detriment. Where appropriate, Citrus has made accruals in accordance with FASB Statement No. 5, Accounting for Contingencies, in order to provide for such matters. Management believes the final disposition of these matters will not have a material adverse effect on the Company’s’ results of operations or financial position.

		Florida Gas plans to seek FERC approval to construct an expansion to increase its natural gas capacity into Florida by approximately 800 MMcf/d. The Phase VIII Expansion includes construction of approximately 500 miles of additional large diameter pipeline and the installation of approximately 170,000 horsepower of additional compression. Pending FERC approval, which is expected in 2009, Florida Gas anticipates an in-service date of 2011, at an approximate cost of $2 billion. Florida Gas has signed a 25-year agreement with FPL for 400 MMcf/d of capacity.

		On February 5, 2008, Citrus entered into a $500 million unsecured construction and term loan agreement (Citrus Credit Agreement) with a wholly owned subsidiary of FPL Group Capital Inc., which is a wholly-owned subsidiary of FPL Group, Inc. Citrus will contribute the proceeds of this loan to Florida Gas in order to finance a portion of the Phase VIII Expansion. The Citrus Credit Agreement provides for a single $500 million draw after Florida Gas’ receipt of a certificate from the FERC authorizing construction of the Phase VIII Expansion and Citrus’ satisfaction of customary conditions precedent. On or before the Phase VIII Expansion in-service date, the construction loan will convert to an amortizing 20-year term loan with a $300 million balloon payment at maturity. The loan requires semi-annual payments of principal beginning five years and six months after the conversion to a term loan. The Citrus Credit Agreement provides for interest on the outstanding principal amount at the rate of six-month LIBOR plus 535 basis points prior to conversion to a term loan and at the twenty-year treasury rate plus 535 basis points after conversion to a term loan. The loan is not guaranteed by Florida Gas and does not include a prepayment option. The Citrus Credit Agreement contains certain customary representations, warranties and covenants and requires the execution of a negative pledge agreement by Florida Gas.

		The Florida Department of Transportation, Florida’s Turnpike Enterprise (FDOT/FTE) has various turnpike widening projects that have or may, over time, impact one or more of Florida Gas’ mainline pipelines co-located in FDOT/FTE rights-of-way. The first phase of the turnpike project includes replacement of approximately 11.3 miles of its existing 18- and 24-inch pipelines located in FDOT/FTE right-of-way in Florida. The estimated cost of such replacement is approximately $110 million, including AFUDC. Florida Gas is also in discussions with the FDOT/FTE related to additional projects that may affect Florida Gas’ 18- and 24-inch pipelines within FDOT/FTE right-of-way. The total miles of pipe that may ultimately be affected by all of the FDOT/FTE widening projects, and any associated relocation and/or right-of-way costs, cannot be determined at this time.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		Under certain conditions, existing agreements between Florida Gas and the FDOT/FTE require the FDOT/FTE to provide any new right-of-way needed for relocation of the pipelines and for Florida Gas to pay for rearrangement or relocation costs. Under certain other conditions, Florida Gas may be entitled to reimbursement for the costs associated with relocation, including construction and right-of-way costs. On January 25, 2007, Florida Gas filed a complaint against FDOT/FTE in the Seventeenth Judicial Circuit, Broward County, Florida, to seek relief for three specific sets of FDOT widening projects in Broward County. The complaint seeks damages for breach of easement and relocation agreements for the one set of projects on which construction has already commenced, and injunctive relief as well as damages for the two other sets of projects upon which construction has yet to commence. On April 24, 2007 the FDOT/FTE filed a complaint against Florida Gas in the Ninth Judicial Circuit, Orange County, Florida, to seek a declaratory judgment that under the existing agreements Florida Gas is liable for the costs of relocation associated with such projects and is not entitled to certain other rights. On August 7, 2007 the Orange County Court granted a motion by Florida Gas to abate and stay the Orange County action. The FDOT/FTE filed an amended answer and counterclaim against Florida Gas on February 8, 2008 in the Broward County action. The counterclaim alleges Florida Gas is subject to estoppel and breach of contract regarding removal from service of the existing pipelines on the project currently under construction and seeks a declaratory judgment that Florida Gas is responsible for all relocation costs and is not entitled to workspace and uniform minimum area precluding FDOT/FTE activity. On February 14, 2008 the case was transferred to the Broward County Complex Business Civil Division 07. As a result, the March 10, 2008 hearing on the motion by Florida Gas for a temporary injunction enjoining the FDOT/FTE interference with the pipelines of Florida Gas will be rescheduled.

		On October 24, 2007, Florida Gas filed a complaint in the US District Court of the Northern District of Florida, Tallahassee Division, against Stephanie C. Kopelousos (Kopelousos) in her official capacity as the Secretary of the Florida Department of Transportation, seeking to enjoin Kopelousos from violating federal law in connection with construction of the FDOT/FTE Golden Glades project, a new toll plaza in Miami-Dade County, Florida. Florida Gas seeks a declaratory judgment that certain Florida statutes are preempted by federal law to the extent such state statutes purport to regulate the abandonment or relocation schedule for the federally regulated pipelines of Florida Gas and prospective preliminary and permanent injunctive relief enjoining Kopelousos from proceeding with construction on the Golden Glades project over and around such pipelines. Kopelousos has filed a motion to dismiss the complaint and Florida Gas has responded. Based upon representations by the FDOT/FTE that the Golden Glades project has been moved to 2013, the parties entered into a joint stipulation of dismissal without prejudice on February 15, 2008.

		Should Florida Gas be denied reimbursement by the FDOT/FTE for any possible relocation expenses, such costs are expected to be covered by operating cash flows and additional borrowings. Florida Gas expects to seek rate recovery at FERC for all reasonable and prudent costs incurred in relocating its pipelines to accommodate the FDOT/FTE to the extent not reimbursed by the FDOT/FTE. There can be no assurance that Florida Gas will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of reimbursement will fully compensate Florida Gas for its costs.

		Florida Gas and Trading previously filed bankruptcy-related claims against Enron and other affiliated bankrupt companies totaling $220.6 million. Of these claims, Florida Gas and Trading filed claims totaling $68.1 and $152.5 million, respectively. Florida Gas and Enron agreed on the amount of the claim at $13.3 million, and Florida Gas assigned its claims to a third party and received $3.4 million in June 2005. Trading’s claim was for rejection damages on two physical/financial swaps and a gas sales contract, as well as certain delinquent amounts owed pre-petition. In March 2005, Enron North America Corp. (ENA) filed objections to Trading’s claim. In September 2006 the judge issued an order which rejected certain of Trading’s arguments and ruled that a contract under which ENA had an in the money position against Trading could be offset against a related contract under which Trading had an in the money position against ENA. The result of the order was a reduction in the allowable amount of Trading’s initial claim to $22.7 million. The parties reached a settlement on the amount of the allowed claim which was approved by the bankruptcy court in March 2007. Citrus fully reserved for the amounts in 2001 and sold the receivable claim in the second quarter of 2007 to a third party for a pre-tax gain on $11.4 million. The gain has been reported in Other, net in the accompanying Consolidated Statements of Income, which is consistent with the presentation of the original write-off recorded in 2001.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

		On March 7, 2003, Trading filed an action, requesting the court to declare that Duke Energy LNG Sales, Inc. (Duke) breached a natural gas trading contract by failing to provide sufficient volumes of gas to Trading. Duke sent Trading a notice of termination of the contract and answered and filed a counterclaim, arguing that Trading failed to timely increase the amount of a letter of credit that was required of Trading under the contract, and that Trading had breached a “resale restriction” on the gas. On June 2, 2003, Trading notified Duke that, because Duke had defaulted on the contract and failed to cure, Trading was terminating the contract effective as of June 5, 2003. On August 8, 2003, Trading sent its final “termination payment” invoice to Duke in the amount of $187 million, and recorded a receivable of $75 million (subsequently reduced by $6.5 million to $68.5 million, reflected in Other Assets at December 31, 2006, to provide for a related settlement, see below). After denying motions for summary judgment by both parties, the judge ordered the parties to attempt to narrow the scope of the issues to be tried. Pre-trial conferences were held in January 2007, a jury was selected and opening arguments were scheduled. Following the judge’s rulings on certain matters, on January 29, 2007, Trading, Citrus, Southern Union and El Paso (collectively, Citrus Parties) entered into a settlement regarding litigation with Spectra Energy LNG Sales, Inc., formerly known as Duke Energy LNG Sales, Inc. (Duke), and its parent company Spectra Energy Corporation (collectively, Spectra), whereby Spectra agreed to pay $100 million to Trading, which was received on January 30, 2007. Citrus recorded a pre-tax gain of $24 million in the first quarter of 2007. This gain has been reported in Other, net in the accompanying Consolidated Statements of Income, which is consistent with the historical results of Trading’s activities.

		In June 2004 the Company recorded an accrual for a contingent obligation of up to $6.5 million to terminate a gas sales contract with a third party. The contingent obligation was extinguished with a payment to the third party on February 6, 2007 of $6.5 million from proceeds resulting from the settlement of the Duke litigation.

		Jack Grynberg, an individual, filed actions for damages against a number of companies, including Florida Gas and Citrus, now transferred to the U.S. District Court for the District of Wyoming, alleging mismeasurement of gas volumes and Btu content, resulting in lower royalties to mineral interest owners. On October 20, 2006, the District Judge adopted in part the earlier recommendation of the Special Master in the case and ordered the dismissal of the case against the defendants. Grynberg is appealing that action to the Tenth Circuit Court of Appeals. Grynberg’s opening brief was filed on July 31, 2007. Respondents filed their brief rebutting Grynberg’s arguments on November 21, 2007. Florida Gas believes that its measurement practices conformed to the terms of its FERC gas tariffs, which were filed with and approved by FERC. As a result, Florida Gas believes that it has meritorious defenses to these lawsuits (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of FERC, and the defense that Florida Gas complied with the terms of its tariffs) and will continue to vigorously defend against them, including any appeal from the dismissal of the Grynberg case. The Company does not believe the outcome of this case will have a material adverse effect on its financial position, results of operations or cash flows.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Southern Natural Gas Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 2^nd day of March 2009.


	SOUTHERN NATURAL GAS COMPANY
	By:	/s/ James C. Yardley
		James C. Yardley
		President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Southern Natural Gas Company and in the capacities and on the dates indicated:


Signature	Title	Date

/s/ James C. Yardley	President and Management Committee	March 2, 2009
James C. Yardley	Member (Principal Executive Officer)

/s/ John R. Sult	Senior Vice President,	March 2, 2009
John R. Sult	Chief Financial Officer and Controller (Principal
	Accounting and Financial Officer)

/s/ Daniel B. Martin	Senior Vice President and Management	March 2, 2009
Daniel B. Martin	Committee Member

/s/ Norman G. Holmes	Senior Vice President,	March 2, 2009
Norman G. Holmes	Chief Commercial Officer and Management Committee Member

/s/ Michael J. Varagona	Vice President and	March 2, 2009
Michael J. Varagona	Management Committee Member

SOUTHERN NATURAL GAS COMPANY

EXHIBIT INDEX
December 31, 2008

Each exhibit identified below is a part of this report. Exhibits filed with this report are designated by “*”. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.


Exhibit
Number		Description
3.A		Certificate of Conversion (Exhibit 3.A to our Current Report on Form 8-K filed with the SEC on November 7, 2007).

3.B		Statement of Partnership Existence (Exhibit 3.B to our Current Report on Form 8-K filed with the SEC on November 7, 2007).

3.C		General Partnership Agreement dated November 1, 2007 (Exhibit 3.C to our Current Report on Form 8-K filed with the SEC on November 7, 2007).

3.D		First Amendment to the General Partnership Agreement of Southern Natural Gas Company, dated September 30, 2008 (Exhibit 3.A to our Current Report on Form 8-K filed with the SEC on October 6, 2008).

4.A		Indenture dated June 1, 1987 between Southern Natural Gas Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee (Exhibit 4.A to our 2006 Form 10-K); First Supplemental Indenture, dated as of September 30, 1997, between Southern Natural Gas Company and the Trustee (Exhibit 4.A.1 to our 2006 Form 10-K); Second Supplemental Indenture dated as of February 13, 2001, between Southern Natural Gas Company and the Trustee (Exhibit 4.A.2 to our 2006 Form 10-K); Third Supplemental Indenture dated as of March 26, 2007 between Southern Natural Gas Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on March 28, 2007); Fourth Supplemental Indenture dated as of May 4, 2007 among Southern Natural Gas Company, Wilmington Trust Company (solely with respect to certain portions thereof) and The Bank of New York Trust Company, N.A. (Exhibit 4.C to our 2007 First Quarter 10-Q); Fifth Supplemental Indenture dated October 15, 2007 by and among SNG, Wilmington Trust Company, as trustee, and The Bank of New York Trust Company, N.A., as series trustee, to Indenture dated as of June 1, 1987 (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on October 16, 2007); Sixth Supplemental Indenture dated November 1, 2007 by and among SNG, Southern Natural Issuing Corporation, Wilmington Trust Company, as trustee, and The Bank of New York Trust Company, N.A., as series trustee, to Indenture dated as of June 1, 1987 (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on November 7, 2007).

4.B		Form of 5.90% Note due 2017 (included as Exhibit A to Exhibit 4.A of our Current Report on Form 8-K filed with the SEC on March 28, 2007).

4.C		Indenture dated as of March 5, 2003 between Southern Natural Gas Company and The Bank of New York Trust Company, N.A., successor to The Bank of New York, as Trustee (Exhibit 4.1 to our Form 8-K filed with the SEC on March 5, 2003).

10.A		First Tier Receivables Sale Agreement dated October 6, 2006, between Southern Natural Gas Company and SNG Finance Company, L.L.C. (Exhibit 10.A to our Form 8-K filed with the SEC on October 13, 2006).

10.B		Second Tier Receivables Sale Agreement dated October 6, 2006, between SNG Finance Company, L.L.C. and SNG Funding Company, L.L.C. (Exhibit 10.B to Form 8-K filed with the SEC on October 13, 2006).

10.C.1		Receivables Purchase Agreement dated October 6, 2006, among SNG Funding Company, L.L.C., as Seller, Southern Natural Gas Company, as Servicer, Starbird Funding Corporation, as the initial Conduit Investor and Committed Investor, the other investors from time to time parties thereto, BNP Paribas, New York Branch, as the initial Managing Agent, the other Managing Agents from time to time parties thereto, and BNP Paribas, New York Branch, as Program Agent (Exhibit 10.C to our Form 8-K filed with the SEC on October 13, 2006).


Exhibit
Number		Description
10.C.2		Amendment No. 1, dated as of December 1, 2006, to the Receivables Purchase Agreement dated as of October 6, 2006, among SNG Funding Company, Southern Natural Gas Company, as initial Servicer, Starbird Funding Corporation and the other funding entities from time to time party hereto as Investors, BNP Paribas, New York Branch, and the other financial institutions from time to time party hereto as Managing Agents, and BNP Paribas, New York Branch, as Program Agent (Exhibit 10.C.1 to our Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on February 28, 2007).

10.C.3		Amendment No. 2, dated as of October 4, 2007, to the Receivables Purchase Agreement dated as of October 6, 2006 among SNG Funding Company, L.L.C., Southern Natural Gas Company, as initial Servicer, Starbird Funding Corporation and other funding entities from time to time party hereto as Investors, BNP Paribas, New York Branch, and the other financial institutions from time to time party hereto as Managing Agents, and BNP Paribas, New York Branch, as Program Agent (Exhibit 10.A to our Quarterly Report on Form 10-Q for the period ended September 30, 2007, filed with the SEC on November 5, 2007).

10.C.4		Amendment No. 3, dated as of October 2, 2008, to the Receivables Purchase Agreement dated as of October 6, 2006 among SNG Funding Company, L.L.C., Southern Natural Gas Company, as initial Servicer, Starbird Funding Corporation and other funding entities from time to time party hereto as Investors, BNP Paribas, New York Branch, and the other financial institutions from time to time party hereto as Managing Agents, and BNP Paribas, New York Branch, as Program Agent (Exhibit 10.A to our Quarterly Report on Form 10-Q for the period ended September 30, 2008, filed with the SEC on November 10, 2008).

*10.C.5		Amendment No. 4, dated as of October 31, 2008, to the Receivables Purchase Agreement dated as of October 6, 2006 among SNG Funding Company, L.L.C., Southern Natural Gas Company, as initial Servicer, Starbird Funding Corporation and other funding entities from time to time party hereto as Investors, BNP Paribas, New York Branch, and the other financial institutions from time to time party hereto as Managing Agents, and BNP Paribas, New York Branch, as Program Agent.

10.D		Registration Rights Agreement, dated as of March 26, 2007, among Southern Natural Gas Company and Banc of America Securities LLC, Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, BNP Paribas Securities Corp., HVB Capital Markets, Inc., Greenwich Capital Markets, Inc., Scotia Capital (USA) Inc., and SG Americas Securities, LLC (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on March 28, 2007).

*21		Subsidiaries of Southern Natural Gas Company

*31.A		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.B		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.A		Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.B		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


Caption	Page
PART I

Item 1. Business		1
Item 1A. Risk Factors		5
Item 1B. Unresolved Staff Comments		12
Item 2. Properties		12
Item 3. Legal Proceedings		12
Item 4. Submission of Matters to a Vote of Security Holders		12

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		13
Item 6. Selected Financial Data		13
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
Item 7A. Quantitative and Qualitative Disclosures About Market Risk		23
Item 8. Financial Statements and Supplementary Data		24
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		46
Item 9A. Controls and Procedures		46
Item 9A(T). Controls and Procedures		46
Item 9B. Other Information		46

PART III

Item 10. Directors, Executive Officers and Corporate Governance		47
Item 11. Executive Compensation		48
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		49
Item 13. Certain Relationships and Related Transactions, and Director Independence		49
Item 14. Principal Accountant Fees and Services		50

PART IV

Item 15. Exhibits and Financial Statement Schedules		51
Signatures		80
EX-10.C.5
EX-21
EX-31.A
EX-31.B
EX-32.A
EX-32.B


Below is a list of terms that are common to our industry and used throughout this document:

/d		= per day

BBtu		= billion British thermal units

Bcf		= billion cubic feet

LNG		= liquefied natural gas

MMcf		= million cubic feet


	Quarters Ended
	March 31		June 30		September 30		December 31		Total
	(In millions)
2008
Operating revenues	$	163	$	125	$	123	$	129	$	540
Operating income		101		61		54		55		271
Net income		95		53		44		43		235

2007
Operating revenues	$	120	$	114	$	121	$	127	$	482
Operating income		67		55		56		64		242
Income from continuing operations		57		47		46		52		202
Discontinued operations, net of income taxes		6		3		6		4		19
Net income		63		50		52		56		221


	Balance at		Charged to				Charged to			Balance
	Beginning		Costs and				Other			at End
Description	of Period		Expenses		Deductions		Accounts			of Period
2008
Legal reserves	$	2		—		—		—		$	2
Environmental reserves		1		—		—		—			1
2007⁽¹⁾
Valuation allowance on deferred tax assets	$	1	$	—	$	—	$	(1	)	$	—
Legal reserves		2		—		—		—			2
Environmental reserves		1		—		—		—			1
2006⁽¹⁾
Allowance for doubtful accounts	$	1	$	—	$	—	$	(1	)	$	—
Valuation allowance on deferred tax assets		1		—		—		—			1
Legal reserves		2		—		—		—			2
Environmental reserves		—		1		—		—			1


⁽¹⁾		Amounts reflect the reclassification of certain entities as discontinued operations.


SNG FUNDING COMPANY, L.L.C.
By:	SNG Finance Company, L.L.C., its Manager




By:	/s/ John J. Hopper
	Name:	John J. Hopper
	Title:	Vice President and Treasurer

SOUTHERN NATURAL GAS COMPANY, as Servicer
By:	/s/ John J. Hopper
	Name:	John J. Hopper
	Title:	Vice President and Treasurer

BNP PARIBAS, acting through its New York Branch, as Program Agent and as Managing Agent for the Starbird Investor Group
By:	/s/ Mary Dierdorff
	Name:	Mary Dierdorff
	Title:	Managing Director


By:	/s/ Phillipe Mojon
	Name:	Phillippe Mojon
	Title:	Vice President


STARBIRD FUNDING CORPORATION,
as a Conduit Purchaser

By:		/s/ Louise E. Colby Name: Louise E. Colby
		Title: Vice President


BNP PARIBAS, acting through its New York Branch,
as Committed Investor

By:		/s/ Mary Dierdorff Name: Mary Dierdorff Title: Managing Director

By:		/s/ Phillipe Mojon

		Name: Phillippe Mojon Title: Vice President


	Jurisdiction of
Company Name	Incorporation	% Held

Southern Natural Gas Company	Delaware
SNG Finance Company, L.L.C.	Delaware		100.00
SNG Funding Company, L.L.C.	Delaware		100.00
Southern Gas Storage Company, L.L.C.	Delaware		100.00
Bear Creek Storage Company	Louisiana		50.00
Southern Natural Issuing Corporation	Delaware		100.00



	/s/ James C. Yardley
	James C. Yardley
	President (Principal Executive Officer) Southern Natural Gas Company



	/s/ John R. Sult
	John R. Sult
	Senior Vice President, Chief Financial Officer and Controller (Principal Accounting and Financial Officer) Southern Natural Gas Company


		/s/ James C. Yardley James C. Yardley
		President (Principal Executive Officer)
		Southern Natural Gas Company

		March 2, 2009


		/s/ John R. Sult John R. Sult
		Senior Vice President, Chief Financial Officer
		and Controller
		(Principal Accounting and Financial Officer)
		Southern Natural Gas Company

		March 2, 2009